Technical Support Document (TSD) for the Final Revisions to the Transport Rule 

Docket ID No. EPA-HQ-OAR-2009-0491 

Final June Revisions Rule State Budgets 

and New Unit Set-Asides TSD

U.S Environmental Protection Agency 

Office of Air and Radiation 

June 2012
 EPA finalized the Transport Rule in July of 2011.1 EPA is now finalizing revisions to certain states’ emission budge

well as revisions to certain new unit set-asides (NUSAs) under the Transport Rule programs. This technical support docume

and calculations used to quantify the state budget revisions and new unit set-aside revisions made in the February revisions ru

included in the June revisions rule.3 Section A below summarizes the net impact of the revisions in each rule on each affecte

Section B below provides a description of each revision and accompanying tables demonstrating the data and calculations ass

relevant to the February revisions rule; Section C below makes the same demonstration for each revision relevant to the June 

a state budget also entails corresponding revisions to the absolute number of allowances put into the relevant new unit set-asi

assurance level5 for the relevant pollutant in that state, as NUSAs and assurance levels are both calculated by applying percen

budget (using the methodologies described in the final Transport Rule). Section A: Summary of Revisions to States’ Emission Budgets and NUSAs.  The February revisions rule affects state emission budgets and/or NUSAs for Arkansas, Florida, Louisiana, MichiganJersey, New York, Texas and Wisconsin. The June revisions rule affects state emissions budgets and/or NUSAs for South C

Ohio, New York, Kansas, Georgia, Arkansas, Louisiana, Missouri, Mississippi, Texas, Kansas and Oklahoma. These revisioat the unit level maintain a consistent application of the methodology described in the final Transport Rule to quantify and elisignificantly contribute to nonattainment and interfere with maintenance of the NAAQS assessed in that rulemaking. The revstate budgets and NUSAs are summarized in Tables A.1. and A.2. below. 

1 Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals (76 FR 48202 See preamble to the “Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” r3 See preamble to the “Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone ” 4 The “Total NUSAs” presented for each state in sections B and C of this document include allowances under both the State NUSA and th

the latter exists in the given state). 

5 EPA finalized in the February revisions rule to amend the effective date of the assurance provisions in all states to start in 2014 instead o
Table A.1.: Final February Revisions to Transport Rule State Budgets and NUSAs 

 2012 – 2013 State Budgets 2014 and beyond State Budgets NU SO2

Annual NOX

Ozone Season NOX SO2

Annual NOX

Ozone Season NOX SO2 Annua

Michigan 5,228 5,228 2Nebraska 3,599 3,599 6Texas 50,517 1,375 1,375 50,517 1,375 1,375 5% 4Florida 819 Arkansas Wisconsin 2,473 7,757 2,473 4% 6New York 3,527 3,485 1,911 3,527 3,485 1,911 2% 2New Jersey 2,096 952 746 679 349 2% 2Louisiana 4,594 4,594 Mississippi 2,154 2,154 * Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 
Table A.2.:Final June Revisions to Transport Rule State Budgets and NUSAs 

 2012 – 2013 State Budgets 2014 and beyond State Budgets  SO2

Annual NO

X

Ozone Season NO

X SO2

Annual NO

X

Ozone Season NO

X SO2 An

South Carolina 8,013 8,013 0 2% Nebraska 3,110 3,110 4% Indiana 5,338 5,338 0 3% Ohio 5,163 2,765 1,221 5,163 2,765 1,221 2% New York 5,444 694 127 5,444 694 127 2% Kansas 452 640 452 5,794 2% Georgia 40,334 13,198 5,762 2% Arkansas1 73 73 Louisiana 89 89 Missouri2 26 26 26 26 3% Mississippi 115 115 Texas 2,731 1,142 2,731 1,142 5% Oklahoma3 859 859 1 This NUSA level for Arkansas takes effect for the 2014 control period and beyond. 2 These NUSA levels for Missouri take effect for the 2013 control period and beyond. 3 Revision applies in 2013 and beyond. 

Section B: Technical Revisions to States’ Transport Rule (TR) Emission Budgets and NUSAs Relevant to February R1) Michigan

EPA is finalizing an increase to Michigan’s 2012 and 2014 annual NO

X budgets as proposed to correct for the assum

Reduction (SCR) technology is currently installed at Monroe Unit 2. This SCR is planned for future installation but is not ex
or by 2014. Therefore, EPA is revising the state’s 2012 and 2014 annual NOX emission budgets6 to reflect projected emission

SCR. This results in a 5,228 ton increase to the state’s annual NO

X budgets in 2012 and 2014. EPA also recognizes that this 

relevant to the calculation of the state’s ozone-season NO

X budget; EPA already included this revised assumption in its quant

the Agency issued the Transport Rule Supplemental Notice of Final Rulemaking (SNFR) (76 FR 87060). 

Table B.1.a.: Calculation to Determine Michigan Annual NOX Budget Revision - Assuming no SCR at 

A B C D 

Plant Unit 

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Input from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from TR_Remedy_Final_2012 (lbs/MMBtu) 

Revised Emission Rate (lbs/MMBtu)

 RE

Calculation A*2/B Monroe 2 1.540 44.437 0.0693 0.3046 

Columns A, B, and C show the NO

X emissions, heat input, and emission rate from the TR_Remedy_Final_2012 mod

to be present at Monroe Unit 2. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NO

X p

version from the September 1, 2010 TR Notice of Data Availability (NODA) (column D).7 This value reflects the NO

X emis

modeling of the Transport Rule as originally proposed, when EPA did not assume an SCR to be present at the unit. This valu

rate expected at the unit at a cost threshold of $500/ton when no SCR is present at the unit. EPA multiplied this NO

X rate by 

column B to obtain a revised emissions projection for the unit (column E). The difference between this revised emission proj

the final Transport Rule remedy analysis emission projection (SCR assumed) determines the amount of the increase to the sta

(column F). 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSA for annual NOX in Michigan remains at 2%. The original and revised values for the state annual NOX budge

set-aside are described in the table below. 

6 Throughout this TSD and throughout the preamble to this proposal, EPA refers to a state budget for 2012 and 2013 as a “2012”state bud

2014 and thereafter as a “2014” state budget. Therefore, any revision of a 2012 state budget would apply to the state budget for 2012 and 

state budget would apply to the state budget for 2014 and thereafter. 7 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev41
Table B.1.b.: Impact of Michigan Annual NOX Budget Revision - Assuming no SCR at 

Monroe Unit 2 (tons) 

Annual NOX

Budget 

Assurance Level Total New Unit Set-Aside * 

% of Budget Tons % of Budget Tons 

2012 Initial 60,193 118% 71,028 2% 1,204 2012 Revised 65,421 - - 2% 1,308 2014 Initial 57,812 118% 68,218 2% 1,156 2014 Revised 63,040 118% 74,387 2% 1,261 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocation

2) Nebraska

EPA is finalizing, as proposed, an increase to Nebraska’s 2012 and 2014 annual NOX budgets to correct for the assum

currently installed at Nebraska City Unit 1. There is no SCR existing, planned, or under construction at the unit. There will the time of the 2012 and 2014 compliance periods as originally assumed in EPA’s determination of Nebraska’s annual NOX b

revising the state’s 2012 and 2014 annual NOX emission budgets to reflect this unit operating without an SCR. This results in 

state’s 2012 and 2014 annual NOX budgets. The calculations to quantify this revision are shown in the table below. 

Table B.2.a.: Calculation to Determine Nebraska Annual NOX Budget Revision – Assuming no SCR at Ne

A B C D 

Plant Unit 

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Input from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from TR_Remedy_Final_2012 (lbs/MMBtu) 

Revised Emission Rate (lbs/MMBtu)

Calculation A*2/B Nebraska City 1 1.602 45.765208 0.070 0.2273 
Columns A, B, and C show the NOX emissions, heat input, and emission rate from the TR_Remedy_Final_2012 mod

to be present. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NOX policy rate” in the N

September 1, 2010 TR Notice of Data Availability (NODA) (column D).8 This value reflects the NOX emission rate assumed 

Transport Rule as originally proposed, when EPA did not assume an SCR to be present at the unit. This value approximates 

the unit at a cost threshold of $500/ton when no SCR is present at the unit. This NOX rate was multiplied by the final remedy 

to obtain a revised emissions value for the unit (column E). The difference between this revised emission projection (no SCR 

remedy emission projection (SCR assumed, column A) determines the amount of the increase to the state’s annual NOX budg

The change to the annual NOX emission budget in Nebraska will result in a small change to the state’s new unit set-a

The reason for the change is that under the methodology established in the final Transport Rule, the state-specific portion of tpercentage equal to the projected emissions from “planned units” divided by the 2014 state budget for the relevant pollutant. projected emissions from planned units remain unchanged, but the budget is increasing. Because the numerator remains unchincreasing, the total new unit set-aside percentage decreases. That is, a smaller percentage of the state emission budget is nee

“planned” new units, because the budget is larger. For Nebraska, the budget revision would decrease the NUSA percentage f

as a result. This is applying the same NUSA methodology that is used for every state in the final Transport Rule, and the cha

outgrowth of the state’s budget revision. This change in the NUSA percentage yields only a marginal change in the absolute Nebraska NUSA. The original and revised values for the state annual NOX budget, assurance level, and new unit set-aside ar

Table B.2.b.: Impact of Nebraska Annual NOX Budget Revision – Assuming no SCR at 

Nebraska City Unit 1 (tons) 

Annual NOX 

Budget 

Assurance Level Total New Unit Set-Aside 

% of Budget Tons % of Budget Tons 

2012 Initial 26,440 118% 31,199 7% 1,851 2012 Revised 30,039 - - 6% 1,802 2014 Initial 26,440 118% 31,199 7% 1,851 2014 Revised 30,039 118% 35,446 6% 1,802 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

8 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev41
3) Texas (Removed FGDs)

EPA is finalizing, as proposed, an increase Texas’s 2012 and 2014 SO2 budgets to correct for the assumption that Flu

technology will be installed by 2012 for W.A. Parish Unit 6, J.T. Deely Unit 1, and J.T. Deely Unit 2. Although the facility oannounced plans to install FGD technology at these facilities, those plans have since been modified. 9 10 There will likely be 

during the 2012 and 2014 compliance periods under the Transport Rule programs. Therefore, EPA is revising the state’s 201

budgets to reflect these units operating without an FGD. This results in a 26,359 ton increase to the state’s 2012 and 2014 SO

quantify this revision are shown in the table below. 

Table B.3.: Calculation to Determine Texas SO2 Budget Revision – Assuming no FGD at J.T. Deely or W A 

 A B C D 

Plant Unit 

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Input from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from TR_Remedy_Final_2012 (lbs/MMBtu) 

Revised Emission Rate (lbs/MMBtu) 

RevEm(10

Calculation A*2/B J T Deely 1 0.917 30.55183083 0.060 0.5800 J T Deely 2 0.914 30.46546708 0.060 0.5800 W A Parish 6 1.211 40.3658592 0.060 0.5800 Total 

Columns A, B, and C show the SO2 emissions, heat input, and emission rate from the TR_Remedy_Final_2012 mode

to be present at these three units. Because no FGD is present, EPA is recalculating projected emissions at these units using ththese units in EPA’s analysis of the base case for the final Transport Rule, as found in the TR_Base_Case_Final for 2012 (co

rates reflect generation at these units without the operation of the assumed FGDs, which did not operate in the final Transpor

were modeled as “dispatchable” controls that were not found to be economic to operate in that scenario.11 The revised SO2 e

multiplied by the final remedy heat input shown in column B to obtain a revised emissions projection for the unit (column E)9 “Corporate Sustainability Report”, CPS Energy, 2010. P.57. Retrieved from http://www.cpsenergy.com/files/Sustainability_Report.pdf 10 Business Wire, (2006). NRG Announces Comprehensive Repowering Initiative [ Press release]. Retrieved from http://phx.corporateir.net/phoenix.zhtml?c=121544&p=irol-newsArticle_Print&ID=874575&highlight 11 See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website 
revised emission projection (no FGD assumed, column E) and the remedy emission projection (FGD assumed, column A) de

increase to the state’s SO2 budget (column F). 

The impacts of all revisions to the Texas state budgets on the state’s NUSAs and assurance levels are shown in Table 

4) Texas (FGD Capture)

EPA is also finalizing an increase to the Texas 2012 and 2014 SO2 budgets to correct for the assumption that the exis

installed at five facilities in Texas (Monticello, Martin Lake, Sandow, Oklaunion, and W A Parish) is capable of treating 100

Although EPA originally assumed removal rates at those units that the facility operators have previously reported, those facil

EPA that those reported removal rates only applied to the flue gas treated at the unit. Because of design limitations, these fac

limited in the amount of flue gas that can be passed through the existing FGD. These facilities report less than 100% pass-threcent Energy Information Administration (EIA) 860 form.12 Consequently, at these facilities, the effective removal rate of th

emissions at the affected units would be lower than the reported removal rate would otherwise indicate. As explained in the fEPA is finalizing this revision based on the SO2 removal efficiency and flue gas treatment data most recently reported for the

operators to the EIA on form 860. The approach results in a final SO2 budget increase of 24,158 tons.13

12 Unless otherwise indicated, EPA used data from EIA form 860 as submitted for the year 2008 to calculate the revisions presented in thi

year for which EPA used EIA form 860 data to inform pollution control removal efficiencies at all units in the Transport Rule power sect

13 EPA originally proposed a related budget increase of 43,708 tons, based on the same calculations presented here but using data reported 
Table B.4.: Calculation to Determine Texas SO2 Budget Revision - Assuming Design SO2 Removal Rates a

Flue Gas Entering FGD 

A B C D E F Total SO2

Emissions from 2012 TR_Remedy_Final (1000 tons) 

EIA 860 Removal Rate (used in budget determination) 

EIA 860 Percent of Flue Gas Entering FGD 

Calculated Removal Rate (used for budget revision estimate) 

Uncontrolled Emissions (assuming no FGD)(1000 tons) 

ReviseEmiss(assumFGD wreviseremov(1000 

 B*C A/(1-B) E*(1-D

Martin Lake 1 1.862841 0.95 0.95 0.903 37.2568208 Martin Lake 2 1.8540181 0.95 0.95 0.903 37.0803634 3.Martin Lake 3 1.745038 0.95 0.95 0.903 34.9007605 3.Monticello 3 2.548471 0.95 0.75 0.713 50.96942 14.Oklaunion 1 2.2321097 0.868 0.81 0.703 16.9099223 5.Sandow 4 1.2522935 0.92 0.83 0.764 15.6536693 3.W A Parish 8 1.5948385 0.85 0.82 0.697 10.6322566 3.Total 13.090 6.438 6.060 5.586 203.403 

Column A shows the projected emissions at these units as originally modeled in the final Transport Rule remedy for 

removal rate that those 2012 emission projections are based on. Column C shows the source reported percent of flue gas ente

the emission rate based on multiplying the removal rate by the percent of flue gas entering FGD. Column E shows a calculat

each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in ord

revised FGD removal rate shown in column D to these uncontrolled emissions, which yields the revised emission projection 

difference between this revised emission projection (lower FGD capture assumed, column F) and the remedy emission projecassumed, column A) determines the amount of the increase to the state’s SO2 budget (column G). The impacts of all revision

state’s NUSAs and assurance levels are shown in Tables B.13.d and B.13.e. 
5) Florida

EPA is finalizing, as proposed, a revision to Florida’s 2012 ozone-season NOX budget to correct for the assumption t

nuclear unit with no NOX emissions, will be available for dispatch in 2012. This unit is not expected to operate in 2012 as it 

outage for repair work. EPA is finalizing an increase to the state’s 2012 ozone season NOX budget by 819 tons to reflect proj

dispatch of fossil-fuel-fired capacity needed to substitute for the generation that EPA originally projected to come from Cryst

calculations to quantify this revision are shown in the table below. 

Table B.5.a.: Calculation to Determine Florida Ozone-Season NOX Budget Revisions to Offset Crystal 

A B C D 

Plant Name 

Unit ID 

Ozone-Season Generation from TR_Remedy_Final_2012 (GWh) 

Average Heat Rate of Replacement Generation (BTU/kWh) 

Average Ozone-Season 

NOX Emission Rate of 

Replacement Generation (lbs/MMBTU) 

Ozo

EmiRepGen

Calculation Crystal River 3 2,976 8,340 0.066 

Column A shows the ozone-season generation projected from the Crystal River Unit 3 under the final Transport Rule 

Columns B and C show the capacity-weighted average heat rate and ozone-season NOX emission rate from combined cycle n

EPA assumes would be likely to increase their dispatch to replace the generation that would otherwise be available from Cry

characterize the emissions of this replacement generation, EPA selected combined cycle units that reported higher utilization Unit 3 was also out of service for repair) compared to their projected utilization under the final Transport Rule 2012 remedy River Unit 3 would operate). Because the originally projected operation of Crystal River Unit 3 did not include any NOX em

Rule, the emissions from likely replacement generation calculated in column D determine the amount of the increase to the stbudget. 

The change to the ozone-season NOX budget for Florida does not impact the percentage of the budget set aside for ne

remains at 2%. The original and revised values for the state ozone-season NOX budget, assurance level, and new unit set-asid

below. 

14 These capacity-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calcu

rate averages used in Final Revisions Rule” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4945). 
Table B.5.b.: Impact of Florida Ozone-Season NOX Budget Revision – Assuming Crysta

River Unit 3 Outage (tons) 

OzoneSeason NOX

Budget 

Assurance Level 

Total Ozone Season NO

New Unit Set-Aside* 

% of Budget Tons % of Budget Tons 

2012 Initial 27,825 121% 33,668 2% 557 2012 Revised 28,644 - - 2% 573 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

6) Arkansas

Plum Point Unit 1 in Arkansas commenced commercial operation on or after January 1, 2010. Such a date qualifies 

“planned” new unit by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the Transp

Transport Rule, EPA did not recognize Plum Point Unit 1as a new unit and therefore omitted its projected emissions in the de

season NOX new unit set-aside for Arkansas. Because there were no other units identified as “planned” new units in Arkansa

the minimum value of 2%.15 EPA is finalizing, as proposed, a revision to the calculation of the Arkansas ozone-season NOX 

“new unit” status of Plum Point Unit 1. The calculations to quantify this revision are shown in the table below. 

Table B.6.a.: Calculation for Arkansas's NUSA 

A Projected 2020 Ozone-Season NOX Emissions from Plum Point (tons) 478B Arkansas Ozone Season NOX State Budget (tons) 15,037C Plum Point's Emissions as a % of Arkansas State Budget (A/B) 3%D Base percentage for new unit set-aside 2%E Total New Unit Set-Aside (C + D) 5%

15 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which 

added if the given state has projected emissions from “planned” new units (76 FR 48291). 
Because Plum Point was the only “planned” new unit for the state of Arkansas, EPA divided its projected emissions 

the state-specific percentage for the new unit set-aside in Arkansas, which rounds to 3%. This value was added to the base pe(2%). The resulting new unit set-aside percentage for ozone season NOX in Arkansas is 5%. This change does not impact th

in any way. However, the new unit set-aside changes by the levels shown below.16

Table B.6.b.: Impact of Ozone Season NOX NUSA revision for Arkansas 

 Initial % Updated% Initial tons Revised tons* New Unit Set-Aside 2% 5% 301 752 Existing Unit Allocation 98% 95% 14,736 14,285 Total 100% 100% 15,037 15,037 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing uallocations 

7) Texas (NUSA)

The Oak Grove Unit 2 in Texas commenced commercial operation on or after January 1, 2010. Such a date qualifies 

“planned” new unit by the definition of that category described in the “Allowance Allocation Final Rule TSD”. However, in 

did not recognize Oak Grove Unit 2 as a new unit and therefore omitted its projected emissions in the determination of the ne

which EPA then calculated to be set at 5%, 3%, and 3% for SO2, annual NOX, and ozone-season NOX, respectively. EPA is f

revision to the Texas new unit set-asides to reflect the “new unit” status of Oak Grove Unit 2. The calculations to quantify th

table below. 

16 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budge

allowance allocations associated with this revision, please see the document entitled “Final June Revisions Rule Unit-Level Allocations u

to this rulemaking. 
Table B.7.: Calculation for Texas's NUSAs 

 SO2 NOXA Projected 2020 Emissions from planned new fossil (tons)* 9,855 2,727 B TX State Budget (tons) 294,471 134,970 C Planned new unit emissions as a % of Texas's State Budget (A/B) 3% 2% D Base percentage for new unit set-aside 2% 2% E Total New Unit Set-Aside (C+D) 5% 4% *Revised to include emissions from Oak Grove Unit 2 

The impact of all revisions to Texas state budgets (and these revisions to the NUSAs) on the state’s NUSAs and assu

Tables B.13.e. 8) Wisconsin

EPA is finalizing, as proposed, a revision to Wisconsin’s 2014 SO2 budget to correct for the assumption that FGD tec

2014 for Weston Unit 3. In the final Transport Rule analysis, this unit was not modeled to build an FGD purely in response t

informing Wisconsin’s 2014 state SO2 budget; instead, its FGD was added as an input assumption in the base case related to 

control was already scheduled for installation. However, Wisconsin Department of Natural Resources (WDNR) has informe

erroneous. Therefore, EPA is finalizing, as proposed, a revision to the state’s SO2 emission budget for 2014 to reflect this un

This results in a 5,605 ton increase to the state’s 2014 SO2 budget. This unit was not originally assumed to have an FGD by 

any revision related to this unit for the state’s 2012 SO2 budget. The calculations to quantify this revision are shown in the ta

Table B.8.a.: Calculation to Determine Wisconsin's SO2 Budget Revision – Assuming 

no FGD at Weston Unit 3 in 2014 (1000 tons) 

A B C 

Plant Name Unit ID 

Emissions from TR_Remedy Final_2014 

Emissions from TR_Remedy Final_2012 Net Budget Revision 

Calculation B-A Weston 3 0.647 6.252 5.605 
Columns A and B show Weston’s Unit 3 SO2 remedy case emissions in 2014 and 2012, respectively. In its modelin

remedy, EPA projected the same total heat input for Weston Unit 3 in both years. However, the total projected emissions are 

FGD was assumed to be operating in that year. Because the projected heat input is constant at this unit between these years, 

difference between the projected emissions at this unit in 2012 (no FGD assumed, column B) and in 2014 (FGD assumed, coamount of the increase to Wisconsin’s 2014 SO2 budget related to this unit, shown in column C. 

EPA is also finalizing, as proposed, a revision to Wisconsin’s 2014 SO2 budget related to scrubbers being installed at 

final Transport Rule analysis, EPA assumed these installations would be wet scrubbers; however, the Wisconsin Department 

has informed EPA that they have been planned and approved as dry scrubbers instead. In its analysis of the final Transport R

rates of 96% for new wet scrubbers and 92% for new dry scrubbers. Therefore, the projected emissions from these units refle

(and consequently lower emissions) than these units would be assumed to achieve with dry scrubber technology. In accordan

finalizing, as proposed, a 2,152 ton increase to the Wisconsin 2014 SO2 emission budget. These units were not originally ass

EPA is not finalizing any revision related to these units for the state’s 2012 SO2 budget. 

Table B.8.b.: Calculation to Determine Wisconsin SO2 Budget Revision - Assuming Dry FG

Columbia in 2014 (1000 tons) 

 A B C D 

Plant Name Unit ID 

Emissions from TR_Remedy Final_2014 (assuming 96% removal) 

Uncontrolled Emissions (assuming no FGD) 

Revised Emissions (assuming 92% removal) 

Net Budget Revision 

Calculation A/(1-0.96) B *(1-0.92) C-A Columbia 1 1.089 27.231 2.179 1.09 Columbia 2 1.063 26.572 2.126 1.063 Total 2.152 53.804 4.304 2.152*Total reflects rounding of calculation performed for both units together

Column A shows the Columbia units’ projected emissions assuming 96% removal characteristic of a new wet scrubb

calculation of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontroin order to allow application of the revised FGD removal rate of 92% to these uncontrolled emissions, which yields the revise
unit in column C. The difference between this revised emission projection (dry scrubbers assumed, column C) and the remed

scrubbers assumed, column A) determines the amount of the increase to the state’s 2014 SO2 budget (column D). 

EPA is also finalizing, as proposed, a revision to Wisconsin’s annual NOX budget for 2012 and 2014 to correct for th

be in place at John P. Madgett Unit 1 in 2012 and 2014. There are currently no plans to have an SCR in place by 2014 at the 

revising the state’s 2012 and 2014 annual NOX budgets by 2,473 tons to reflect the operation of the unit without an SCR. Th

revision are shown in the table below. EPA also recognizes that this revised input assumption is relevant to the calculation o

budget; EPA already included this revised assumption in its quantification of that budget when the Agency issued the Transp

Table B.8.c.: Calculation to Determine Wisconsin Annual NOX Budget Revision - Assuming no SCR a

 A B C D E 

Plant Name 

Unit 

ID 

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons) 

Heat Input from 

TR_Remedy_Final_2012 

(TBtu) 

Remedy Emission Rate 

fromTR_Remedy_Final_2012 

(lbs/MMBtu) 

Revised 

Emission 

Rate 

(lbs/MMBtu)

Revise

Emissio

(1000 

tons) 

Calculation A*2/B D x B/

J P Madgett B1 0.588922429 23.55689678 0.05 0.26 3.062 

Columns A, B, and C shows the emissions, heat input, and emission rate from the 2012 remedy modeling for the J P Mad

present, EPA is recalculating projected emissions at this unit using the emission rate shown for this units in EPA’s analysis o

Transport Rule, as found in the TR_Base_Case_Final for 2012 (column D). This annual NOX emission rate reflects generatio

operation of the assumed SCR, which did not operate in the final Transport Rule base case because it was modeled as a “disp

found to be economic to operate in that scenario.17 The J P Madgett emission rate without operating an SCR (column D) mul

(column B) yields the projected emissions from the unit if no SCR were assumed to be in place. The difference between the 

SCR is in place (column E) and the projected emissions when an SCR is assumed (column A) determines the amount of the i

2014 annual NOX budgets (column F). 

The revisions to the SO2 emission budget for Wisconsin results in a small change to the state’s new unit set-aside percent

change is that under the methodology established in the final Transport Rule, the state-specific portion of the NUSA is calcul

17 See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4420) 
the projected emissions from “planned units” divided by the state budget for the relevant pollutant. In the case of Wisconsin

planned units remain unchanged, but the budget is increasing.18 Because the numerator remains unchanged but the denomina

unit set-aside percentage for SO2 decreases. That is, a smaller percentage of the state emission budget is needed to cover emi

units, because the budget is larger. For Wisconsin, the budget revision decreases the NUSA percentage for SO2 from 5% to 4

the same NUSA methodology that is used for every state in the final Transport Rule, and the change in percentage is simply a

budget revision. While this change in the NUSA percentage reduces the absolute number of allowances in the Wisconsin NU

amount under the final Transport Rule, the revised NUSA still contains more than enough allowances in 2012 and 2014 to co

“planned” new units in Wisconsin, with the remainder still available for “potential” new units to enter the programs during threvised values for the state SO2 budget, assurance level, and new unit set-aside are described in the table below. 

Table B.8.d.: Impact of Wisconsin Budget Revisions – Assuming no FGD at Weston Unit 3

SCR at JP Madgett, and dry FGD at Columbia (tons) 

 Program Budget 

Assurance Level Total New Unit Set-A

% of Budget Tons % of Budget To

2012 Initial SO2 79,480 118% 93,786 5% 3,92012 Revised SO2 79,480 - - 4% 3,12014 Initial SO2 40,126 118% 47,349 5% 2,02014 Revised SO2 47,883 118% 56,502 4% 1,92012 Initial Annual NO

X 31,628 118% 37,321 6% 1,8

2012 Revised Annual NO

X 34,101 - - 6% 2,0

2014 Initial Annual NO

X 30,398 118% 35,870 6% 1,8

2014 Revised Annual NO

X 32,871 118% 38,788 6% 1,9

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

18 While this relationship is also true for annual NOX, the revisions to Wisconsin’s annual NOX budget do not yield a different calculated 

originally determined 6% under the final Transport Rule. 
9) New York

EPA is finalizing, as proposed, an increase to the New York state annual NOX, ozone-season NOX, and SO2 budgets 

near-term operational constraints affecting specific units in New York City and Long Island. These revisions are based on th

constraints that apply to certain generators in New York City and Long Island, which are referred to here as the N-1-1 Contin

Rules, and local out-of-merit-order dispatch conditions. Each calculation of the near-term emission impact found to be assoc

documented below; the results are summarized in Table B.9.f. 

N-1-1 Contingency Certain parts of the Con Edison system in New York City are required to be designed and operated for the occurrenc

known as an N-1-1 contingency; these requirements are in addition to any requirements for the first (N-1) contingency on wh

power system is operated. The local rules that determine the operation and unit commitment for New York City are New Yor(NYSRC) rules I-R1 through I-R4.19 To meet the requirements of these rules, the New York Independent System Operator (N

supplemental commitment of units in the New York City zone. The rules require additional reserves from in-city combustion 

commitment of steam units where needed to ensure sufficient locational reserves and to guard against a potential interruption facility that could disrupt its generation and perturb local grid stability. These rules are in effect throughout the year and are 

daily and hourly unit commitment process specific to New York City. Depending on the expected load level and the pattern will commit steam units to meet intermediate load levels, while placing CTs in reserve to meet morning and afternoon peak rNYISO must meet multiple requirements for reserves and energy and comply with the NYSRC rules, the exact pattern of dis

constraints varies throughout the year. Because the steam units in the city have long startup times and 24-hour minimum run 

these units in advance in order to preserve the ability to dispatch the CTs during peak load or in response to grid disruption co

The dispatch requirements apply throughout the year, but there are also additional environmental requirements uniqu

During the ozone season, the NYISO determines generator operations subject to local environmental regulations that require steam units before seeking additional power from CTs when needed, to balance the need to meet energy and reserve requirem

emissions for these units. NYISO implements these requirements through an operational procedure that requires commitmen

specific plants that would otherwise not be economic to dispatch, in order to ensure these combustion turbines can be dispatc

19 See Rule I-R1, NYSRC Reliability Rules For Planning and Operating the New York State Power System, Version 29, New York State R

January 7, 2011, p. 66. 
steam units in New York City (Arthur Kill, Ravenswood and Astoria), these procedures mean that one or more steam units mozone season.20

Minimum Oil Burn Rules In order to ensure that units do not go offline if there is a loss of natural gas supply to New York City, the NYSRC ru

provisions that require natural gas units to be prepared to switch from natural gas to oil immediately upon notice of a loss of n

provisions are implemented through utility applications to the NYISO for special summer and winter dispatch conditions des

generators must be prepared to burn oil in each season.21 For certain oil/gas steam units that do not have the ability to switch 

to oil, this provision means that they must already be burning oil at the times that they may be notified to switch. As a resultoperate using oil at certain times of the year. For New York City, Con Edison applies to revise this procedure twice each yeafor the winter or summer season.22 There is a separate and similar minimum oil burn rule affecting units in Long Island.23

Since in the current outlook the price of oil is much higher than gas for the same heat input, EPA recognizes that thes

captured in projections of economic generating behavior. As such, EPA has calculated revised emission projections at the un

burn rules based on the fraction of heat input each unit reported as oil in 2010 to the Energy Information Administration.24

Local Out-of–Merit-Order Dispatch Long Island’s ability to import electricity is limited to tie lines within the state between Con Ed and the Long Island 

interstate cables connecting Long Island with the Independent System Operator for New England (ISO-NE) and the PJM Intefrom ISO-NE and PJM are direct current (DC) lines that are not dispatched in real time and not controlled by the NYISO, the load from within New York State is subject to overall import limitations. Local conditions limiting the immediate-term abilibetween southern New York state and Long Island lead NYISO to dispatch more generation from units on Long Island than rmodeling, such as EPA’s IPM projections, would suggest. The NYISO Operating Study25 shows that NYISO is limited to ap

dispatchable import capacity into Long Island on a sustainable hourly basis. Even if this line were fully loaded for all hours o

amount of imports into Long Island that NYISO can dispatch would be 7.5 TWh; however, in EPA’s modeling of the final Tr

20 See Analysis of New York City Averaging Plans for Compliance with NOx Emissions Limitations, New York Independent System Oper21 NYSRC Reliability Rules For Planning and Operating the New York State Power System, Version 29, New York State Reliability Coun

R3 & I-R5 Reliability Rule Applications. Rule I-R3 governs New York City operations, Rule I-R5 Long Island Operations. 

22 See ConEd, Application for the Loss of Generator Gas Supply – New York City, OC Meeting – May 12, 2011, for the requirements for t23 See the document, Long Island Gas Burn Procedures – 2011, in the docket for the TR Rule Revisions Proposal, Docket. 24 The EIA data used for this calculation is available at: http://www.eia.gov/cneaf/electricity/page/eia906_920.html. 25 See NYISO Operating Study Summer 2011 and Appendices, New York Independent System Operator, July 14, 2011, page C-3. 
9.7 TWh of net imports from NYISO dispatch. Under these conditions, NYISO would have to increase local Long Island ge

local load while respecting the 7.5 TWh limitation on imports from the rest of NYISO, notwithstanding the economic merit odetermine projected emissions associated with this local out-of-merit-order dispatch, EPA assumed that this generation would 

plant, on the basis that one unit at Northport is modeled to have economic generation even without this local import limitatio

units at Northport have heat rates that differ by less than one percent from the Northport unit that was modeled to dispatch. 

Calculation of New York City Revised Generation and Emissions – Plant Level To reflect the requirements of the NYSRC rules as implemented by the NYISO for New York City, EPA is assuming 

units at three steam plants in New York City (Arthur Kill, Ravenswood, and Astoria) would occur in the form of two units at 

minimum of 50% capacity at the times that the contingency conditions apply to necessitate non-economic operation of these 

establish the assumed minimum generation at each facility that would dispatch in the immediate term to meet the conditions 

independent of the economic merit of that generation within the larger region as originally modeled. Where EPA’s originally unit was less than this minimum, EPA has calculated here the difference in generation from the unit and, most importantly, th

that generation, in order to inform the revision to the New York state budgets under the Transport Rule. Calculations were p

season and non-ozone season periods. During the ozone season, these dispatch conditions were assumed to apply 100% of thyear (non-ozone season), they were assumed to apply 40% of the time, reflecting historically observed seasonal differences in NO

X emissions from this additional generation at these units were calculated using each unit’s heat rate and NO

X emission ra

its IPM modeling. The results from these unit-level calculations are shown in Tables B.9.a and B.9.b. 

To account for the effects of the minimum oil burn rule in New York City, EPA calculated SO2 emissions from the re

assuming that the unit would burn oil for the same share of its projected heat input (including the revisions discussed above) These calculations for New York City units are shown in Table B.9.b. To estimate additional SO2 emissions, the IPM emissio

residual fuel oil was used. The IPM emission rate for NO

X is the same for natural gas and oil, so no changes in NO

X emission

additional use of oil. 
Table B.9.a.: Ozone Season NOX Revised Unit-Level Emission Projections for New York City for N-1-1 Contin

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and 

A B C D E F G H I J 

UniqueID Plant Name 

Capacity 

(MW) 

Capacity 

Factor 

Heat 

Rate 

(BTU/

kWh) 

NOX Rate 

(lbs/ 

MMBtu) 

Heat 

Input 

(TBtu) 

Generation 

(GWh) 

Minimum 

Capacity 

Factor 

Revised 

Generation 

(GWh) 

Calculation 

2490_B_20 Arthur Kill 335 31.7% 10389 0.08 4.056 390 50.0% 615 2490_B_30 Arthur Kill 491 31.7% 10198 0.10 5.836 572 50.0% 901 2500_B_10 Ravenswood 356 0.0% 11714 0.07 0.000 0 50.0% 653 2500_B_30 Ravenswood 940 0.0% 11624 0.07 0.000 0 50.0% 1,726 8906_B_30 Astoria 366 44.4% 10123 0.06 6.039 597 50.0% 672 8906_B_40 Astoria 373 44.4% 10117 0.06 6.150 608 50.0% 685 
Table B.9.b.: Annual NOX and SO2 Revised Unit-Level Emission Projections for New York C

for N-1-1 Contingency Operation and Minimum Oil Burn Rule 

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and Emissions 

A B C D E F G H I J K 

Unique 

ID 

Plant 

Name 

Capacity 

(MW) 

Capacity 

Factor 

Heat 

Rate 

(BTU/

kWh) 

NOX

Rate (lbs/ 

MMBtu) 

Heat 

Input 

(TBtu

) 

Generation 

(GWh) 

Minimum 

Capacity 

Factor 

Revised 

Generation 

(GWh) 

Additional 

Generation 

beyond 

IPM (GWh) 

Add

N

Emi

(to

Calculation (I-H) (E*

2

2490_ B_20 

Arthur Kill 335 13.3% 10389 0.08 4.056 390 32.6% 956 566 

2490_ B_30 

Arthur Kill 491 13.3% 10198 0.10 5.836 572 32.6% 1,401 829 

2500_ B_10 

Ravenswood 356 0.0% 11714 0.07 0.000 0 32.6% 1,015 1,015 

2500_ B_30 

Ravenswood 940 0.0% 11624 0.07 0.000 0 32.6% 2,682 2,682 

8906_ B_30 Astoria 366 18.6% 10123 0.06 6.039 597 32.6% 1,044 448 8906_ B_40 Astoria 373 18.6% 10117 0.06 6.150 608 32.6% 1,064 456 8906_ B_50 Astoria 359 18.6% 10120 0.06 5.921 585 18.6% 585 0 *Assumes the IPM v.4.10_FTransport SO2 emission rate of 1.04 lbs/MMBTU for oil-fired generation 

Calculation of Long Island Revised Generation and Emissions – Plant Level As discussed above, EPA is assuming that an additional 2.2 TWh of generation beyond the level projected in IPM m

will occur on Long Island in the immediate term to allow NYISO to dispatch enough power to meet local load while respecti

into Long Island. EPA is assuming that this additional generation would occur at the Northport facility distributed across its units have virtually identical heat rates, EPA assumes that these units would be operated at the same capacity factors; EPA thcapacity factor at each unit in order to produce an additional 2.2 TWh beyond the original IPM projection. In concert with th

calculated additional ozone-season NOX, annual NOX, and SO2 emissions from these Long Island units in the same way as fo

shown above. These calculations are provided in Tables B.9.c and B.9.d below. 
Table B.9.c.: Ozone Season NOX Revisions for Long Island for Import Limited Generation

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and E

A B C D E F G H I J 

UniqueID 

Plant 

Name 

Capacity 

(MW) 

Capacity 

Factor 

Heat 

Rate 

(BTU/

kWh) 

NOX

Rate 

(lbs/ 

MMBtu) 

Heat 

Input 

(TBtu) 

Generation 

(GWh) 

Minimum 

Capacity 

Factor 

Required 

Generation 

(GWh) 

A

G

Calculation 

2516_B_2 Northport 390 23.4% 10580 0.11 3.534 334 38.5% 551 2516_B_3 Northport 391 0.0% 10634 0.14 0.000 0 38.5% 552 2516_B_4 Northport 385 0.0% 10663 0.10 0.000 0 38.5% 544 

Table B.9.d.: Annual NOX and SO2 Revisions for Long Island for Import Limited Generation and Minimum 

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and Emissions

A B C D E F G H I J K 

Unique

ID 

Plant 

Name 

Capacity 

(MW) 

Capacity 

Factor 

Heat 

Rate 

(BTU/

kWh) 

NOX

Rate 

(lbs/ 

MMBtu) 

Heat 

Input 

(TBtu

) 

Generation 

(GWh) 

Minimum 

Capacity 

Factor 

Revised 

Generation 

(GWh) 

Additional 

Generation 

beyond 

IPM (GWh) 

Add

N

Emi

(to

Calculation (I-H) (E*

2

2516_ B_2 Northport 390 9.8% 10580 0.11 3.534 334 25.1% 858 524 2516_ B_3 Northport 391 0.0% 10634 0.14 0.000 0 25.1% 860 860 2516_ B_4 Northport 385 0.0% 10663 0.10 0.000 0 25.1% 847 847 Assumes the IPM v.4.10_FTransport SO2 emission rate of 1.04 lbs/MMBTU for oil-fired generation
Calculation of Revisions to New York State BudgetsIn order to maintain the balance of electricity supply and demand as originally projected in the Transport Rule analys

increased generation at the units shown above would offset the need for an equivalent amount of generation originally projec

efficient generators in the system. To calculate the net change in projected emissions for each pollutant relevant to establishiTransport Rule, EPA assumes that the increased generation at the units shown above displaces previously projected generatioNew York City, as that unit is representative of more efficient generation that is preferred in IPM determinations of least-cosare shown in Table B.9.e. 

Table B.9.e.: Calculation of Emissions from Displaced Generation at a Representative Combined Cyc

York* 

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BAnnual 8,227 7,600 0.01 Ozone Season 4,397 7,600 0.01 *Assumed heat rate and emission rates are taken from the 500 CC unit in New York City, as shown in NEEDS v4.10_FTransport. 

To quantify the revisions to Transport Rule state budgets in New York, EPA has calculated the net emissions change 

unit-level generation presented in this section, including the displaced emissions shown in Table B.9.e. These calculations are 
Table B.9.f.: Calculation to Determine Net New York SO2, Annual NOX, and Ozone 

Season NOX Budget Revisions 

 SO2 Annual NOX

Ozone Season 

NOX

A 

Additional Emissions Due to New York City Revisions 1,805 2,408 1,257

B 

Additional Emissions Due to Long Island Revisions 1,723 1,390 821

C Displaced Emissions 0 313 167D 

Net Emissions Change For New York (A+B-C) 3,527 3,485 1,911

The revisions to the annual and ozone season NOX emission budgets for New York result in small changes to the state’s new 

annual NOX and ozone season NOX. The reason for these changes is that under the methodology established in the final Tran

portion of the NUSA is calculated as the percentage equal to the projected emissions from “planned units” divided by the stat

pollutant. In the case of New York, the projected emissions from planned units remain unchanged, but the budgets are increa

remains unchanged but the denominator is increasing, the total new unit set-aside percentage for annual NOX and ozone seaso

smaller percentage of the state emission budgets is needed to cover emissions from “planned” new units, because the budgets 

budget revisions decrease the NUSA percentages for both annual NOX and ozone season NOX from 3% to 2% as a result. Thi

methodology that is used for every state in the final Transport Rule, and the change in percentages is simply an outgrowth of 

Despite the lower percentage value, the absolute number of allowances in the New York NUSAs rises in accordance with the 

York. The original and revised values for the state’s emission budgets, assurance levels, and new unit set-asides are describe

26 While this relationship is also true for SO2, the revisions to New York’s SO2 budget do not yield a different calculated NUSA percentag

2% under the final Transport Rule. 
Table B.9.g.: Impact of New York Budget Revisions – Assuming Out-of-Merit-Order Dispa

at New York City and Long Island Units (tons) 

 Program Budget 

Assurance Level 

Total New U

Set-Aside* 

% of 

Budget Tons 

% of 

Budget To

2012 Initial SO2 27,325 118% 32,244 2% 52012 Revised SO2 30,852 - - 2% 62014 Initial SO2 18,585 118% 21,930 2% 32014 Revised SO2 22,112 118% 26,092 2% 42012 Initial Annual NOX 17,543 118% 20,701 3% 32012 Revised Annual NOX 21,028 - - 2% 42014 Initial Annual NOX 17,543 118% 20,701 3% 32014 Revised Annual NOX 21,028 118% 24,813 2% 42012 Initial Ozone-Season NOX 8,331 - - 3% 12012 Revised Ozone-Season NOX 10,242 121% 12,393 2% 22014 Initial Ozone-Season NOX 8,331 121% 10,081 3% 12014 Revised Ozone-Season NOX 10,242 121% 12,393 2% 2*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

10) New Jersey

EPA is finalizing, as proposed, an increase to New Jersey’s SO2, annual NOX, and ozone season NOX budgets to corr

scrubber and SCR technology would be installed by 2012 at BL England Unit 1. The scrubber and SCR had been planned to 

Consent Order (AO) with New Jersey, but an agreement with the state allowed for a delay in installation of the control techno

Additionally, the AO requires that this unit only run during the ozone season.27 Therefore, EPA is adjusting the state’s 2012 

27 Personal Correspondence from Bill O’Sullivan, New Jersey Department of Environmental Protection, to Sam Napolitano. September 2
unit operating only in the ozone season and without a scrubber or SCR. This results in a 2,096 ton increase to the state’s 201

increase to the state’s 2012 annual NO

X budget; and a 397 ton increase to the state’s 2012 ozone season NO

X budget. As dis

assumes that the generation previously projected at BL England Unit 1 outside of the ozone season (and thus inconsistent wit

at well-controlled combined cycle units within the state, and their associated emissions are factored into the revisions to New 

The calculations of revised 2012 emissions from ozone-season operation of BL England Unit 1 are shown in Table B

Table B.10.a.: Calculation to Determine Revised Ozone Season Emissions at BL England U

 A B C D E Pollutant 

Ozone Season Emissions from TR_Remedy Final_2012 (1000 tons) 

Ozone Season Heat Input from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from TR_Remedy_Final_2012 (lbs/MMBtu) 

Revised Emission Rate (lbs/MMBtu) 

RevisSeasoEmiss(1000 

Calculation A*2/B D SO2 0.175 2.282 0.153 2.190 NO

X 0.105 2.282 0.092 0.440 

Columns A, B, and C show the emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling 

devices were originally assumed to be present at BL England Unit 1. Because neither a scrubber nor SCR is required by the emission rates by removing the impact of the scrubber28 and adopting the “controlled NO

X policy rate” in the NEEDS version 

TR Notice of Data Availability (NODA), which does not reflect operation of an SCR at that unit (column D).29 These values 

expected at the unit at a cost threshold of $500/ton when no scrubber or SCR is present at the unit. These emission rates wer

input shown in column B to obtain a revised emissions value for the unit (column E). The difference between these revised escrubber or SCR assumed, column E) and the remedy emission projections (scrubber and SCR assumed, column A) determinozone-season emissions (column F). 

28 The SO2emission rate for BL England Unit 1 in TR_Remedy Final_2012 was 0.153 lbs/MMBtu. Removing the impact of that previous

removal rate of 93% yields an uncontrolled SO2 emission rate of 2.19 lbs/MMBtu. 

29 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev4
 Since the AO does not allow BL England Unit 1 to run outside of the ozone season, EPA has also determined the emthe previously projected generation for that unit occurring outside of the ozone season. EPA assumes that this decrease in prBL England Unit 1 would be offset by increasing generation at New Jersey combined cycle units,30 represented in these calcu

heat rate and emission rates equal to the generation-weighted average of New Jersey combined cycle units.31 The calculation

replaced generation are shown in Table B.10.b. As discussed below, the heat and emission rates of the generic unit were reviconsistency across all revisions using a generation weighted average, instead of capacity weighted. Additionally, two cogene

from this average based on comments. 

Table B.10.b.: Calculation of Emissions at New Jersey Combined Cycle Units from 

Replacing BL England Unit 1’s Non-Ozone-Season Generation 

 A B C D  Pollutant 

BL England Unit 1 Non-Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Average Heat Rate of Replacement Generation (Btu/kWh) 

Emission Rate of Replacement Generation (lbs/MMBtu) 

Emissions from Replacement Generation (1000 tons) 

Calculation A*B*C/(2000*100SO2 253.3 7413 0 NO

X 253.3 7413 0.0136 0.0

EPA calculated the SO2 and NO

X emissions in Table B.10.b by multiplying the replaced generation (column A) by th

(column B) and relevant emission rate (column C). 

In order to calculate appropriate revisions to New Jersey’s 2012 SO2, annual NO

X, and ozone season NO

X state budg

revisions to BL England Unit 1, EPA calculated the net change in projected emissions of each pollutant as shown in Table B.

30 Excluding cogeneration facilities, whose generation is not solely based on electricity demand. 31 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Final Revisions Rule” found in the Tranport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4945). 
Table B.10.c.: Calculation to Determine New Jersey 2012 Budget Revisions Due to Change

BL England Unit 1 (1000 tons) 

Quantity Calculation Value 

A Additional SO2 Emissions from BL England 2B SO2 Emissions from Replacement Generation C 

BL England Unit 1 Non-Ozone Season SO2 Emissions from 

TR_Remedy Final_2012 0

D Net SO2 Emissions Due to Revisions of BL England Unit 1 A+B-C 2E Additional Ozone Season NOX Emissions from BL England 0F Annual NOX Emissions from Replacement Generation 0G 

BL England Unit 1 Non-Ozone Season NOX Emissions from 

TR_Remedy Final_2012 0

H 

Net Annual NOX Emissions Due to Revisions of BL England Unit 

1 E+F-G 0

I 

Net Ozone Season NOX Emissions Due to Revisions of BL 

England Unit 1 =E 0

The revisions to New Jersey’s 2012 SO2 and annual NOX budgets are determined by combining the revised emission

without FGD or SCR at BL England Unit 1 (rows A and E) with the net change in emissions from replacing BL England’s ge

year (row B minus row C for SO2, row D minus row E for NOX). The revision to New Jersey’s 2012 ozone-season NOX bud

in ozone season NOX emissions at BL England due to removing the SCR (row E). 

EPA is also finalizing, as proposed, an increase to New Jersey’s annual NOX and ozone season NOX budgets to reflec

operational constraints affecting six plants, based on information provided by the system operator demonstrating that norther

order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions descrdocumentation that appear likely to necessitate non-economic generation at the units displayed below during the implementaprograms. Specifically, EPA is assuming additional generation will be dispatched at six plants (Bergen, Edison, Essex, Kear

Generating Stations) based on the average capacity factor representing the frequency the unit has recently been called on to o
calculated from dispatch logbook data provided by PSEG.32 As discussed later in this section, EPA assumes that the addition

these six facilities would offset generation that would otherwise come from combined cycle units within the state, and the rev

budgets are based on the net change to projected emissions taking that offsetting factor into account. The net impact of these 2014 budgets are a 679 ton increase in annual NOX and a 349 ton increase in ozone season NOX. 

The calculations of the increase in ozone season NOX and annual NOX emissions due to out-of-merit-order dispatch a

Tables B.10.d and B.10.e, respectively. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR

rate, generation, and emission rate are shown (columns A to G). The average out-of-merit-order capacity factor is shown in cgeneration for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity hours in either the ozone season or year (column I). The additional heat input required was calculated by multiplying the incr

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by mu

input by the unit’s NOX emission rate. 

Table B.10.d.: Calculation to Determine New Jersey Ozone Season NOX Budget Revisions - Assuming Out-of-Merit-O

A B C D E F G H I Plant Name 

Unique ID 

Capacity 

(MW) 

2012 Ozone Season NOX

Emission from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

NOX

Emission 

Rate from 

TR_Remedy 

Final_2012 

(lbs/MMBtu) 

Ozone Season Average Out-OfMeritOrder Capacity Factor 

Additional Ozone Season Generation (GWh)* 

Calculation C*H*3.67Bergen 

2398_ G_1101 114 0.010 8841 55.18 0.04 20.1% 84.

Bergen 

2398_ G_1201 114 0.010 8841 55.18 0.04 20.1% 84.

Bergen 

2398_ G_1301 114 0.010 8841 55.18 0.04 20.1% 84.

32 See the spreadsheet “New Jersey Minimum Noneconomic Dispatch” provided by PSEG on September 26, 2011, in the docket for this r
Bergen 

2398_ G_1401 114 0.010 8841 55.18 0.04 20.1% 84.

Bergen 

2398_ G_1501 219 0.020 8841 106.00 0.04 20.1% 161.

Bergen 

2398_ G_2101 163 0.004 9241 78.89 0.01 22.0% 131.

Bergen 

2398_ G_2201 163 0.004 9241 78.89 0.01 22.0% 131.

Bergen 

2398_ G_2301 224 0.006 9241 108.42 0.01 22.0% 181.

PSEG Edison 

2400_ G_11 42 0.003 16763 1.37 0.27 2.1% 3.

PSEG Edison 

2400_ G_12 42 0.003 16862 1.37 0.27 2.1% 3.

PSEG Edison 

2400_ G_13 42 0.003 16893 1.37 0.27 1.8% 2.

PSEG Edison 

2400_ G_14 42 0.003 16947 1.37 0.26 1.7% 2.

PSEG Edison 

2400_ G_21 42 0.003 17182 1.37 0.28 2.0% 3.

PSEG Edison 

2400_ G_22 42 0.003 16846 1.37 0.27 2.0% 3.

PSEG Edison 

2400_ G_23 42 0.003 16979 1.37 0.27 1.9% 2.

PSEG Edison 

2400_ G_24 42 0.004 17184 1.37 0.30 1.6% 2.

PSEG Edison 

2400_ G_31 42 0.003 16953 1.37 0.27 1.6% 2.

PSEG Edison 

2400_ G_32 42 0.003 16984 1.37 0.27 1.8% 2.

PSEG Edison 

2400_ G_33 42 0.003 17033 1.37 0.27 1.9% 2.

PSEG Edison 

2400_ G_34 42 0.003 16950 1.37 0.26 1.7% 2.

PSEG Essex 

2401_ G_101 42 0.003 16968 1.37 0.30 2.6% 4.
PSEG Essex 

2401_ G_102 42 0.004 17066 1.37 0.30 2.4% 3.

PSEG Essex 

2401_ G_103 42 0.004 17188 1.37 0.30 2.1% 3.

PSEG Essex 

2401_ G_104 42 0.004 17167 1.37 0.30 2.2% 3.

PSEG Essex 

2401_ G_111 46 0.004 16816 1.50 0.30 2.5% 4.

PSEG Essex 

2401_ G_112 46 0.004 17154 1.50 0.30 2.6% 4.

PSEG Essex 

2401_ G_113 46 0.004 16847 1.50 0.30 2.3% 3.

PSEG Essex 

2401_ G_114 46 0.004 16726 1.50 0.30 2.3% 3.

PSEG Essex 

2401_ G_121 46 0.004 16455 1.50 0.30 2.2% 3.

PSEG Essex 

2401_ G_122 46 0.004 16889 1.50 0.30 2.2% 3.

PSEG Essex 

2401_ G_123 46 0.004 16771 1.50 0.30 2.3% 3.

PSEG Essex 

2401_ G_124 46 0.001 16758 1.50 0.08 2.2% 3.

PSEG Essex 

2401_ G_9 81 0.022 10633 13.67 0.30 0.0% 0.

PSEG Kearny 

2404_ G_10 134 0.012 18700 4.45 0.30 0.5% 2.

PSEG Kearny 

2404_ G_11 134 0.012 18700 4.45 0.30 0.3% 1.

PSEG Kearny 

2404_ G_N121 43.8 0.003 9667 7.28 0.09 0.2% 0.

PSEG Kearny 

2404_ G_N122 43.7 0.003 9791 7.26 0.09 0.2% 0.

PSEG Kearny 

2404_ G_N123 43.8 0.003 10109 7.28 0.09 0.0% 0.

PSEG Kearny 

2404_ G_N124 43.7 0.003 9704 7.26 0.09 0.2% 0.
PSEG Linden 

2406_ G_5 86 0.005 12110 14.51 0.06 2.1% 6.

PSEG Linden 

2406_ G_6 86 0.005 12601 14.51 0.05 2.1% 6.

PSEG Linden 

2406_ G_7 84 0.005 12155 14.17 0.06 2.5% 7.

PSEG Linden 

2406_ G_8 84 0.006 13314 14.17 0.06 2.6% 8.

PSEG Sewaren 

2411_ B_1 104 - 12377 0.00 0.12 6.4% 24.

PSEG Sewaren 

2411_ B_2 118 - 13581 0.00 0.16 4.7% 20.

PSEG Sewaren 

2411_ B_3 107 - 14500 0.00 0.15 6.0% 23.

PSEG Sewaren 

2411_ B_4 124 - 14500 0.00 0.14 3.8% 17.

TOTAL 1,1*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 
Table B.10.e.: Calculation to Determine New Jersey Annual NOX Budget Revisions - Assuming Out-of-Merit-Ord

A B C D E F G H I Plant Name 

NEEDS Unique ID 

Capacity 

(MW) 

2012 Annual NOX

Emission (1000 tons) from TR_Remedy Final_2012 

Heat Rate from TR_Remedy Final_2012 (Btu/kWh) 

GWh Annual from TR_Remedy Final_2012 

NOX

Emission 

Rate from 

TR_Remedy 

Final_2012 

(lbs/MMBtu) 

Annual Average Out-OfMeritOrder Capacity Factor 

Additional Annual Generation (GWh)* 

Calculation C*H*8.76Bergen 

2398_ G_1101 114 0.015 8841 78.98 0.04 36.3% 362.

Bergen 

2398_ G_1201 114 0.015 8841 78.98 0.04 36.3% 362.

Bergen 

2398_ G_1301 114 0.015 8841 78.98 0.04 36.3% 362.

Bergen 

2398_ G_1401 114 0.015 8841 78.98 0.04 36.3% 362.

Bergen 

2398_ G_1501 219 0.028 8841 151.72 0.04 36.3% 696.

Bergen 

2398_ G_2101 163 0.005 9241 86.87 0.01 35.5% 507.

Bergen 

2398_ G_2201 163 0.005 9241 86.87 0.01 35.5% 507.

Bergen 

2398_ G_2301 224 0.007 9241 119.38 0.01 35.5% 697.

PSEG Edison 

2400_ G_11 42 0.003 16763 1.37 0.27 1.0% 3.

PSEG Edison 

2400_ G_12 42 0.003 16862 1.37 0.27 1.0% 3.

PSEG 2400_ 42 16893 0.27 0.8% 2.
Edison G_13 0.003 1.37 

PSEG Edison 

2400_ G_14 42 0.003 16947 1.37 0.26 0.7% 2.

PSEG Edison 

2400_ G_21 42 0.003 17182 1.37 0.28 1.0% 3.

PSEG Edison 

2400_ G_22 42 0.003 16846 1.37 0.27 1.0% 3.

PSEG Edison 

2400_ G_23 42 0.003 16979 1.37 0.27 0.8% 3.

PSEG Edison 

2400_ G_24 42 0.004 17184 1.37 0.30 0.7% 2.

PSEG Edison 

2400_ G_31 42 0.003 16953 1.37 0.27 0.8% 2.

PSEG Edison 

2400_ G_32 42 0.003 16984 1.37 0.27 0.8% 3.

PSEG Edison 

2400_ G_33 42 0.003 17033 1.37 0.27 0.8% 2.

PSEG Edison 

2400_ G_34 42 0.003 16950 1.37 0.26 0.7% 2.

PSEG Essex 

2401_ G_101 42 0.003 16968 1.37 0.30 1.6% 6.

PSEG Essex 

2401_ G_102 42 0.004 17066 1.37 0.30 1.5% 5.

PSEG Essex 

2401_ G_103 42 0.004 17188 1.37 0.30 1.3% 4.

PSEG Essex 

2401_ G_104 42 0.004 17167 1.37 0.30 1.4% 5.

PSEG Essex 

2401_ G_111 46 0.004 16816 1.50 0.30 1.7% 6.

PSEG Essex 

2401_ G_112 46 0.004 17154 1.50 0.30 1.8% 7.

PSEG Essex 

2401_ G_113 46 0.004 16847 1.50 0.30 1.5% 6.

PSEG Essex 

2401_ G_114 46 0.004 16726 1.50 0.30 1.6% 6.
PSEG Essex 

2401_ G_121 46 0.004 16455 1.50 0.30 1.9% 7.

PSEG Essex 

2401_ G_122 46 0.004 16889 1.50 0.30 2.0% 7.

PSEG Essex 

2401_ G_123 46 0.004 16771 1.50 0.30 1.9% 7.

PSEG Essex 

2401_ G_124 46 0.001 16758 1.50 0.08 1.8% 7.

PSEG Essex 

2401_ G_9 81 0.022 10633 13.67 0.30 0.1% 0.

PSEG Kearny 

2404_ G_10 134 0.012 18700 4 0.30 0.3% 3.

PSEG Kearny 

2404_ G_11 134 0.012 18700 4 0.30 0.2% 2.

PSEG Kearny 

2404_ G_N121 43.8 0.004 9667 9 0.09 0.3% 1.

PSEG Kearny 

2404_ G_N122 43.7 0.004 9791 9 0.09 0.3% 1.

PSEG Kearny 

2404_ G_N123 43.8 0.004 10109 9 0.09 0.3% 1.

PSEG Kearny 

2404_ G_N124 43.7 0.004 9704 9 0.09 0.4% 1.

PSEG Linden 

2406_ G_5 86 0.005 12110 15 0.06 1.2% 9.

PSEG Linden 

2406_ G_6 86 0.005 12601 15 0.05 1.3% 9.

PSEG Linden 

2406_ G_7 84 0.005 12155 14 0.06 1.9% 14.

PSEG Linden 

2406_ G_8 84 0.006 13314 14 0.06 1.6% 11.

PSEG Sewaren 

2411_ B_1 104 - 12377 0 0.12 2.8% 25.

PSEG Sewaren 

2411_ B_2 118 - 13581 0 0.16 1.9% 19.

PSEG Sewaren 

2411_ B_3 107 - 14500 0 0.15 2.7% 25.
PSEG Sewaren 

2411_ B_4 124 - 14500 0 0.14 1.6% 17.

TOTAL 4,1*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8,760 hours of possible operation in the year; that factor is divided by 1,000 to yield 

As calculated in Table B.10.f, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at New Jersey combined cycle units, shown in these calculations as a representative unit with a heat rate (column 

C) equal to the generation-weighted average of New Jersey combined cycle units.33 This is a change from the proposal where 

was used to determine the characteristics of the representative unit. The change was made for consistency across states where 

representative unit was used to offset increased generation due to out-of-merit order dispatch. Additionally, as explained in thcomments received, EPA excluded any identified cogeneration units from these calculations. Finally, separate annual and ozrates were calculated and the applicable ones were used as the situation warranted. The ozone season and annual NOX emissi

displaced generation (column D) were calculated by multiplying that generation by the average heat rate and the relevant emicombined cycle unit. 

Table B.10.f.: Calculation of Emissions from Displaced Generation at New Jersey Combined Cy

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BAnnual 4,119 7,413 0.0136 Ozone Season 1,142 7,454 0.0144 

The total revisions finalized to New Jersey’s state budgets due to the revisions at BL England and accounting for the 

demonstrated in Table B.10.g. The increase in emissions due to the changes at BL England Unit 1, which only impact the 20increase in emissions due to the out-of-merit-order generation, which impact both the 2012 and 2014 budgets. The emissions 33 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Final Revisions Rule” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4945). 
displaced by the out-of-merit-order generation was subtracted from the increase in emissions to determine the net emission b

(row D). 

Table B.10.g.: Calculation to Determine Net New Jersey SO2, Annual NOX, and Ozone Season NOX Budget R

2012 

SO2

Annual 

NOX

Ozone 

Season NOX SO2

A

A Net Emissions Increases Due to Changes at BL England Unit 1 2,096 273 397 0 B Additional Emissions Due to Out-Of-Merit-Order Generation 0 887 410 0 C Displaced Emissions from Out-Of-Merit-Order Generation 0 208 61 0 D Net Budget Revisions for New Jersey (A+B-C) 2,096 952 746 0 

The original and revised values for the state SO2, annual NOX, and ozone season NOX budgets, assurance levels, and 

described in Table B.10.h. 
Table B.10.h.: Impact of New Jersey Budget Revisions – Assuming No FGD or SCR at B

England Unit 1 in 2012 and Out-of-Merit-Order Dispatch at Six Facilities (tons) 

 Program Budget 

Assurance Level 

Total New 

Set-Aside

% of 

Budget Tons 

% of 

Budget T

2012 Initial SO2 5,574 118% 6,577 2% 2012 Revised SO2 7,670 - - 2% 2014 Initial SO2 5,574 118% 6,577 2% 2014 Revised SO2 5,574 118% 6,577 2% 2012 Initial Annual NOX 7,266 118% 8,574 2% 2012 Revised Annual NOX 8,218 - - 2% 2014 Initial Annual NOX 7,266 118% 8,574 2% 2014 Revised Annual NOX 7,945 118% 9,375 2% 2012 Initial Ozone-Season NOX 3,382 121% 4,092 2% 2012 Revised Ozone-Season NOX 4,128 - - 2% 2014 Initial Ozone-Season NOX 3,382 121% 4,092 2% 2014 Revised Ozone-Season NOX 3,731 121% 4,515 2% *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

11) Louisiana

EPA is finalizing, as proposed, an increase to Louisiana’s ozone season NOX budget for 2012 and 2014 to reflect the 

operational constraints affecting units at five plants, based on information provided by the system operator demonstrating thaorder dispatch areas in Louisiana: the West of the Atchafalaya Basin (WOTAB), Down Stream of Gypsy (DSG), and Amite Sin the final Transport Rule did not incorporate the immediate-term local conditions described in recently submitted documentnecessitate non-economic generation at the units displayed below during the implementation of the Transport Rule programs
additional generation will be dispatched at five plants (Nelson, Nine Mile Point, Michoud, Little Gypsy, and Waterford) baserepresenting the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispa

provided by Entergy.34 As discussed later in this section, EPA assumes that the additional generation dispatched from these f

generation that would otherwise come from combined cycle units within the state, and the revision to Louisiana’s state budge

projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season N

increase. 

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at the five facilitie

each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation 

and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor 

additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-ord

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the increm

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by mu

input by the unit’s NOX emission rate. 

Table B.11.a.: Calculation to Determine Louisiana Ozone Season NOX Budget Revisions - Assuming Out-of-Merit-O

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/ kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX Rate 

(lbs/MMBtu) 

Ozone Season Average Out-OfMeritOrder Capacity Factor 

Additional Ozone Season Generation

Calculation C*H*3.67R S Nelson 

1393_ B_3 153 0 10476 0 0.151 16% 89.

R S Nelson 

1393_ B_4 500 0 10419 0 0.128 23% 422.

Little Gypsy 

1402_ B_1 244 0 9978 0 0.278 7% 62.

34 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” 
Little Gypsy 

1402_ B_2 415 0 10032 0 0.098 3% 45.

Little Gypsy 

1402_ B_3 545 0 10179 0 0.311 24% 480.

Nine Mile Point 

1403_ B_3 132 0 10264 0 0.149 11% 53.

Nine Mile Point 

1403_ B_4 738 0 9955 0 0.337 31% 840.

Nine Mile Point 

1403_ B_5 753 0 9841 0 0.298 34% 940.

Michoud 

1409_ B_1 100 0 11427 0 0.042 0% 0.

Michoud 

1409_ B_2 230 0 10997 0 0.207 30% 253.

Michoud 

1409_ B_3 530 0 11288 0 0.105 45% 875.

Waterford 1 & 2 

8056_ B_1 400 0 10238 0 0.123 3% 44.

Waterford 1 & 2

8056_ B_2 405 0 10137 0 0.116 7% 104.

Total 4,211.

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table B.11.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Louisiana combined cycle units, shown in these calculations. Generation was first offset from Washington Pari

EPA that the plant was never completed and part were deconstructed,35 with the remaining generation offset from a represen

(column D) and emission rate (column E) equal to the generation-weighted average of Louisiana combined cycle units.36 As 

based on comments received, EPA excluded any identified cogeneration units from these calculations. Finally, separate annu

and heat rates were calculated and the applicable ones were used as the situation warranted. The ozone season NOX emission

35 See Docket No. EPA-HQ-OAR-2009-0491-4803.36 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Final Revisions Rule” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4945). 
generation (column G) were calculated by multiplying that generation by the average heat rate and the relevant emission rate cycle unit. The total displaced emissions (column H) were calculated by adding the emissions from the operation of Washing

emissions displaced from the representative unit. 

Table B.11.b.: Calculation of Emissions from Displaced Generation at Louisiana Combined Cyc

A B C D E F G 

Program Period 

Displaced Generation (GWh) 

Generation Displaced from Washington Parish (GWh) 

Generation Displaced from other Combined Cycles (GWh) 

Heat Rate (BTU/ kWh) 

NOX Emission 

Rate (lbs/MMBTU)

Displaced Emissions from Washington Parish (tons) 

DisplacEmissiofrom oCombiCycles (tons) 

Calculation A-B C*D*EOzone Season 4,212 1,806 2,405 7,480 0.031765081 67.7 28

The total revision proposed to Louisiana’s state budget due to the out-of-merit-order dispatch is calculated in Table B

with the generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions du

generation (row A) to determine the net emission budget changes for Louisiana (row C). 

Table B.11.c.: Calculation to Determine Net Louisiana 

Ozone Season NOX Budget Revisions (tons) 

A 

Additional Emissions Due to Out-Of-Order-Merit Dispatch 4,947

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 353

C 

Net Emission budget Change For Louisiana (A-B) 4,594
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are de

Table B.11.d.: Impact of Louisiana Ozone-Season NOX Budget Revisions – 

Assuming Out-of-Merit-Order Dispatch at Five Facilities (tons) 

 Budget

Assurance Level Total New Unit Set-Aside* 

% of Budget Tons % of Budget Tons 

2012 Initial 13,432 121% 16,253 3% 403 2012 Revised 18,026 - - 3% 541 2014 Initial 13,432 121% 16,253 3% 403 2014 Revised 18,026 121% 21,811 3% 541 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

12) Mississippi

EPA is finalizing, as proposed, an increase to Mississippi’s ozone season NOX budget in 2012 and 2014 to reflect the 

operational constraints affecting units at three plants, based on information provided by the system operator demonstrating th

out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local con

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the im

Rule programs. Specifically, EPA is assuming additional generation will be dispatched at three plants (Rex Brown, Gerald Abased on the average capacity factor representing the frequency the unit is projected to be called to operate out-of-merit-orde

dispatch modeling projections provided by Entergy.37 As discussed later in this section, EPA assumes that the additional gen

three facilities would offset generation that would otherwise come from combined cycle units within the state, and the revisio

is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes o

budget is a 2,154 ton increase. 

37 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” 

(Docket No. EPA-HQ-OAR-2009-0491-4729). 
The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at the three facilit

For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generaFinal_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order ca

column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiply

by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calc

additional heat input by the unit’s NOX emission rate. 

Table B.12.a.: Calculation to Determine Mississippi Ozone Season NOX Budget Revisions - Assuming out-of-merit-or

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/ kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio(GWh) 

Calculation C*H*3.6Rex Brown 

2053_ B_4 200 0 14500 0 0.228 4% 29

Baxter Wilson 

2050_ B_1 475 0 10655 0 0.318 7% 122

Baxter Wilson 

2050_ B_2 771 0 10511 0 0.422 18% 509

Gerald Andrus 

8054_ B_1 670 0 10748 0 0.209 33% 811

Total 1472

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table B.12.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Mississippi combined cycle units, shown in these calculations as a representative unit with a heat rate (column B
equal to the generation-weighted average of Mississippi combined cycle units.38 The emission and heat rates of this represent

proposal because the proposal’s calculations used annual, rather than ozone-season, data; the calculations for this final rule u

Additionally, as explained in the preamble and based on comments received, EPA excluded any identified cogeneration units 

ozone season NOX emissions associated with the displaced generation (column D) were calculated by multiplying that genera

and the relevant emission rate at the representative combined cycle unit. 

Table B.12.b.: Calculation of Emissions from Displaced Generation at Mississippi Combined Cy

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BOzone Season 1,473 7,570 0.026 

The total revision to Mississippi’s state budget due to the out-of-merit-order dispatch is calculated in Table B.12.c. T

the generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to t

generation (row A) to determine the net emission budget changes for Mississippi (row C). 

Table B.12.c.: Calculation to Determine Net Mississippi 

Ozone Season NOX Budget Revisions (tons) 

A

Additional Emissions Due to Out-Of-Order-Merit Dispatch 2,299

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 145

C

Net Change in Emission budget For Mississippi (A-B) 2,154

38 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Final Revisions Rule” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4945). 
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are de

Table B.12.d.: Impact of Mississippi Ozone-Season NOX Budget Revisions – 

Assuming Out-of-Merit-Order Dispatch at Three Facilities (tons) 

 Budget

Assurance Level Total New Unit Set-Aside* 

% of Budget Tons % of Budget Tons 

2012 Initial 10,160 121% 12,294 2% 203 2012 Revised 12,314 - - 2% 246 2014 Initial 10,160 121% 12,294 2% 203 2014 Revised 12,314 121% 14,900 2% 246 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

13) Texas (Out-of-Merit-Order Dispatch)

EPA is finalizing, as proposed, an increase Texas’s annual NOX and ozone season NOX budgets in 2012 and 2014 to 

term operational constraints affecting units at two plants, based on information provided by the system operator demonstratin

the Atchafalaya regions are out-of-merit-order dispatch areas. EPA's analysis in the final Transport Rule did not incorporate 

conditions described in recently submitted documentation that appear likely to necessitate non-economic generation at the un

implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at twSabine) based on the average capacity factor representing the frequency the unit is projected to be called to operate out-of-me

immediate-term dispatch projections provided by Entergy.39 As discussed later in this section, EPA assumes that the addition

these two facilities would offset generation that would otherwise come from combined cycle units within the state, and the re

are based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes 

ozone season NOX budgets is a 1,375 ton increase to each budget. 

The calculations of the increase in annual and ozone season NOX emissions due to out-of-merit-order dispatch at the 

B.13.a. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, 

39 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” 

(Docket No. EPA-HQ-OAR-2009-0491-4729). 
Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order ca

column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiply

by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calcadditional heat input by the unit’s NO

X emission rate. 

Table B.13.a.: Calculation to Determine Texas NOX* Budget Revisions - Assuming Out-of-Merit-Order Dis

A B C D E F G H I Plant Name 

Unique ID 

Capacity 

(MW) 

2012 Ozone Season NOX

Emission from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average Out-OfMeritOrder Capacity Factor 

Additional Ozone SeaGeneration(GWh) 

Calculation C*H*3.67Lewis Creek 

3457_ B_1 229 0 10325 0 0.020 47% 395

Lewis Creek 

3457_ B_2 230 0 10600 0 0.020 55% 464

Sabine 

3459_ B_1 230 0 11172 0 0.168 37% 312

Sabine 

3459_ B_2 230 0 10225 0 0.152 30% 253

Sabine 

3459_ B_3 420 0 10588 0 0.104 32% 493

Sabine 

3459_ B_4 530 0 9800 0 0.143 45% 875

Sabine 

3459_ B_5 480 0 10442 0 0.090 15% 264

Total 3,059
*Note: Since the increase in generation at these units is limited to the ozone season, the revised emissions calculated here apply equally to determination of the annual NO

**The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,00

As calculated in Table B.13.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Texas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) an

equal to the generation-weighted average of Texas combined cycle units.40 The ozone season NOX emissions associated with 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

Table B.13.b.: Calculation of Emissions from Displaced Generation at Texas Combined Cycle 

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BOzone Season 3,059 7,376 0.019 *Note: Since the increase in generation at these units is limited to the ozone season, the revised emissions calculated here apply equally to determination o

ozone-season NOX state budgets. 

The total revisions to the Texas state budgets due to out-of-merit-order dispatch are calculated in Table B.13.c. The e

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Texas (row C). 

Table B.13.c.: Calculation to Determine Net Texas Annual 

NOX and Ozone Season NOX Budget Revisions* 

A 

Additional Emissions Due to Out-Of-Order-Merit Dispatch 1,590

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 214

C

Net Emission budget Change For Texas (A-B) 1,375

*Note: Since the increase in generation at these units is limited to the ozone season, the revised emissions calculated here apply equally to determination of the annual 

40 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Final Revisions Rule” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4945). 
NOX and ozone-season NOX state budgets.

In addition to the revisions summarized in Table B.13.c., the revisions to Texas state budgets outlined above in sectio

support document are summarized in Table B.13.d. The cumulative impacts of all of the technical revisions to the Texas budg

summarized in Table B.13.e.41

Table B.13.d.: Summary of Texas SO2

Budget Revisions 

Removed FGD Revision 26,359FGD Capture Revision 24,158Total SO2 Budget Revision 50,517

41 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budge

allowance allocations associated with this revision, please see the document entitled “Final June Revisions Rule Unit-Level Allocations u

to this rulemaking.
Table B.13.e.: Impact of Texas Budget Revisions – Assuming Removed FGDs and Revised F

Capture at Certain Units, Revised NUSAs for Oak Grove 2, and Out-of-Merit-Order Dispat

Two Facilities (tons) 

 Program Budget 

Assurance Level 

Total New 

Set-Asid

% of 

Budget Tons 

% of 

Budget T

2012 Initial SO2 243,954 118% 287,866 5% 12012 Revised SO2 294,471 - - 5% 12014 Initial SO2 243,954 118% 287,866 5% 12014 Revised SO2 294,471 118% 347,476 5% 12012 Initial Annual NOX 133,595 118% 157,642 3% 42012 Revised Annual NOX 134,970 - - 4% 52014 Initial Annual NOX 133,595 118% 157,642 3% 42014 Revised Annual NOX 134,970 118% 159,265 4% 52012 Initial Ozone-Season NOX 63,043 121% 76,282 3% 12012 Revised Ozone-Season NOX 64,418 - - 4% 22014 Initial Ozone-Season NOX 63,043 121% 76,282 3% 12014 Revised Ozone-Season NOX 64,418 121% 77,946 4% 2*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 
Section C: Technical Revisions to States’ TR Emission Budgets and NUSAs Relevant to June Revisions Rule 

1) South Carolina

EPA is finalizing, based on comments, an increase to South Carolina’s 2012 and 2014 SO2 budgets to correct for the 

Desulfurization (FGD) technology is currently installed at the W S Lee Power Plant. There is no FGD planned or under cons

EPA is finalizing an increase to the state’s 2012 and 2014 SO2 emission budgets to reflect projected emissions without these u

results in a 8,013 ton increase to the state’s SO2 budgets in 2012 and 2014. 

Table C.1.a.: Calculation to Determine South Carolina Budget Adjustment 

- Assuming no FGD at W S Lee 

 A B C D Plant Unit 

Emissions from TR_Remedy Final_2012 (1000 tons) 

HI from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from from TR_Remedy_Final_2012 (lbs/MMBtu) 

Adjusted Emission Rate (lbs/MMBtu)

AdjuEmi(100tons

Calculation A*2/B D x W S Lee 1 0.480468932 3.907141013 0.246 1.320 W S Lee 2 0.477953387 3.886684777 0.246 1.320 W S Lee 3 0.903656715 7.169244286 0.252 1.320 Total 

In Table C.1.a., columns A, B, and C show the SO2 emissions, heat input, and emission rate from the TR_Remedy_F

FGD is assumed to be present at W S Lee. Because no FGD is present, EPA modified the emission rate to reflect the TR Bas

analysis where the FGD is assumed not to dispatch at the unit. This value approximates the emission rate expected at the uni

when no FGD is operating at the unit. EPA multiplied this SO2 rate by the remedy heat input shown in column B to obtain a 

the unit (column E). The difference between this revised emission projection (no FGD assumed) and the final Transport Rule 

projection (FGD assumed) determines the amount of the increase to the state’s SO2 budget (column F). 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSA for SO2 in South Carolina remains at 2%. The original and revised values for the state SO2 budget, assuranc

are described in the table below. 
Table C.1.b.: Impact of South Carolina's SO2 Budget Revision - Assuming no FGD at W 

S Lee(tons) 

SO2

Budget 

Assurance Level 

Total New 

Unit Set-Asid

* 

% of 

Budget Tons 

% of 

Budget Ton

2012 Before June Revisions Rule 88,620 - - 2% 1,772012 After June Revisions Rule 96,633 - - 2% 1,932014 Before June Revisions Rule 88,620 118% 104,572 2% 1,772014 After June Revisions Rule 96,633 118% 114,027 2% 1,93*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

2) Nebraska

EPA is finalizing, based on comments, an increase to Nebraska’s 2012 and 2014 SO2 budgets to correct for the assum

currently installed at Whelan Energy Center Unit 1. There is no FGD existing, planned, or under construction at the unit. Thavailable at the time of the 2012 and 2014 compliance periods as originally assumed in EPA’s determination of Nebraska’s S

finalizing a revision the state’s 2012 and 2014 SO2 emission budgets to reflect this unit operating without an FGD. This resu

state’s 2012 and 2014 SO2 budgets. The calculations to quantify this revision are shown in the table below. 
Table C.2.a.: Calculation to Determine Nebraska Budget Adjustment - Assuming no FGD at Whelan Ene

 A B C D Plant Unit 

Emissions from TR_Remedy Final_2012 (1000 tons) 

HI from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from from TR_Remedy_Final_2012 (lbs/MMBtu) 

Adjusted Emission Rate (lbs/MMBtu)

AdjEm

Calculation A*2/B D Whelan Energy Center 1 0.255767801 6.394195158 0.0800 0.81 2

EPA is also finalizing, based on comments, a revision to Nebraska’s 2012 and 2014 SO2 budgets related to FGD tec

Center Unit 2 and Nebraska City Unit 2. In the final Transport Rule analysis, EPA assumed these installations would be wet 

Public Power District has informed EPA through comment that they are dry scrubbers instead.42 In its analysis of the final T

SO2 removal rates of 95.9% for the wet scrubbers. However, dry scrubbers generally have lower SO2 removal rates. EPA re

for these two units to reflect the lower SO2 removal rates as reported by the sources themselves on EIA form 860 (95% remo

90.5% removal for Whelan unit 2). The revised projected SO2 emissions from these units reflect the lower SO2 removal rate 

emissions) than these units would be assumed to achieve with wet scrubber technology. In accordance with this revision, EP

increase to the Nebraska’s 2012 and 2014 SO2 emission budget. 

42 See Docket No. EPA-HQ-OAR-2009-0491-4754. 
Table C.2.b.: Calculation to Determine Nebraska's Annual SO2 Budget Adjustment 

- Assuming dry FGD in place of Wet FGD (1000 tons) 

 A B C D  Unit 

Emissions from TR_Remedy Final_2012 (95.9% removal) 

Emissions assuming no FGD 

Emissions assuming EIA 860 Rates 

Emission Adjustment 

Calculation A/.041 

B*.05 or .095 C-A 

Nebraska City 2 1.142 27.854 1.393 0.251 Whelan Energy Center 2 0.399 9.732 0.925 0.526 Total 1.541 37.585 2.317 0.776 

Column A shows the units’ projected emissions assuming 95.9% removal characteristic of the assumed wet scrubber

of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissi

allow application of the revised FGD removal rates of 95% for Nebraska City Unit 2 and 90.5% for Whelan Energy Center Uemissions, which yields the revised emission projection for each unit in column C. The difference between this revised emis

assumed, column C) and the remedy emission projection (wet scrubbers assumed, column A) determines the amount of the in

2014 SO2 budget (column D). The combined impact of these two budget adjustments is a 3,110 tons increase to the state’s 2

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSA for SO2 in Nebraska remains at 4%. The original and revised values for the state SO2 budget, assurance leve

described in the table below. 
Table C.2.c.: Nebraska SO2 Budget, Assurance Level, and NUSA Before and After 3,800 

SO2 Budget Adjustment 

SO2

Budget 

Assurance Level 

Total New Un

Set-Aside * 

% of 

Budget Tons 

% of 

Budget Ton

2012 Before June Revisions Rule 65,052 - - 4% 2,602012 After June Revisions Rule 68,162 - - 4% 2,722014 Before June Revisions Rule 65,052 118% 76,761 4% 2,602014 After June Revisions Rule 68,162 118% 80,431 4% 2,72*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

3) Indiana

EPA is finalizing, based on comments, an increase to Indiana’s 2012 and 2014 SO2 budgets to correct for the assump

currently installed at Gallagher Units 2 and 4. There is no FGD existing, planned, or under construction at the units. These u

technology installed with an SO2 removal rate that achieves approximately 60% sulfur removal according to data reported by 

Therefore, EPA is finalizing a revision to the state’s 2012 and 2014 SO2 emission budgets to reflect this unit operating with D

by the commenter, the units are also subject to a NSR settlement agreement that imposes a .8 lbs/MMBtu limit for SO2 at the 

its assumption to ensure that with the adjustment from FGD to DSI, that the source still honored its emission rate limits. Thi

to the state’s 2012 and 2014 SO2 budgets. The calculations to quantify this revision are shown in the table below. 
Table C.3.a.: Calculation to Determine Indiana SO2 Budget Adjustment - 

Assuming DSI in place of FGD in 2012 and 2014 (1000 tons) 

 A B C D 

Emissions from TR_Remedy Final_2012 (86% removal) 

HI from TR_Remedy_Final_2012 (TBtu) 

Emissions assuming .8 lbs/MMBtu Emission Rate 

Emission Adjustment 

Calculation B*.8 C-A Gallagher 2 1.066211595 6.957289314 2.783 1.717 Gallagher 4 1.08608673 7.08697939 2.835 1.749 Total 2.152 14.044 5.618 3.465 

Column A shows the units’ projected emissions with the 86% removal rate assumed in the TR_Remedy_Final. Colu

projected for each unit in the TR remedy. This heat input is multiplied by the .8 lbs/mmbtu emission rate allowed under the semissions value in column C – which reflects the DSI technology rather than FGD technology. The difference between this r

(DSI assumed, column C) and the remedy emission projection (FGD assumed, column A) determines the amount of the increSO2 budget (column D). The combined impact of these two budget adjustments is a 3,465 tons increase to the state’s 2012 an

EPA is also finalizing, based on comments, an adjustment to the 2012 and 2014 SO2 budget for Indiana based on the 

through the FGD at Gibson Unit 5. The commenter noted that because of this scrubber’s design limitation, the facility may b

gas that can be passed through the existing FGD. The Gibson unit in Indiana reports less than 100% pass-through of flue gas 

Consequently, at this unit, the effective removal rate of the FGD as applied to total SO2 emissions would be lower than the re

otherwise indicate. EPA is finalizing an adjustment to the Indiana budget to account for the inability of the Gibson unit to pa

scrubber. Consistent with the approach EPA used to finalize similar revisions, EPA is finalizing this revision based on the SO

gas treatment data reported for these scrubbers by the facility operators to the EIA on form 860. The approach results in a fin

increase of 1,873 tons. 
Table C.3.b.: Calculation to Determine Indiana SO2 Budget Adjustment – Assuming Revised SO2 rem

FGD 

 A B C D E F Plant Name 

Unit ID 

Total SO2

Emissions from TR_Remedy_Final (1000 tons) 

EIA 860 Removal Rate (used in budget determination)

EIA 860 Percent of Flue Gas Entering FGD 

Calculated Removal Rate (used for budget revision estimate) 

Uncontrolled Emissions (assuming no FGD)(1000 tons) 

Revised Emission(assuming FGD with revised removal rate) (100tons) 

Calculation B*C A/(1-B) E*(1-D) Gibson 5 4.928346201 0.95 98% 0.931 98.566924 6.80111

Column A shows the projected emissions at the unit as originally modeled in the final Transport Rule remedy for 20

removal rate that the 2012 emission projections are based on. Column C shows the source reported percent of flue gas enteri

effective removal rate based on multiplying the removal rate by the percent of flue gas entering FGD. Column E shows a cal

at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in o

revised FGD removal rate shown in column D to these uncontrolled emissions, which yields the revised emission projection 

difference between this revised emission projection (lower FGD capture assumed, column F) and the remedy emission projecassumed, column A) determines the amount of the increase to the state’s SO2 budget (column G). 

The combined impact of these two changes to Indiana’s 2012 and 2014 budget is 5,338 tons. This budget change wi

percent of the budget set aside for new units. Under the methodology in the final Transport Rule, the NUSA for SO2 in India

and revised values for the state SO2 budget, assurance level, and new unit set-aside are described in the table below. 
Table C.3.c: Impact of Indiana's 2012 and 2014 SO2 Budget Revision 

SO2

Budget 

Assurance Level 

Total New Un

Set-Aside * 

% of 

Budget Tons 

% of 

Budget Ton

2012 Before June Revisions Rule 285,424 - - 3% 8,562012 After June Revisions Rule 290,762 - - 3% 8,722014 Before June Revisions Rule 161,111 118% 190,111 3% 4,832014 After June Revisions Rule 166,449 118% 196,410 3% 4,99*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

4) Ohio

EPA is finalizing, based on comments, an increase to Ohio’s 2012 and 2014 annual NOX and ozone-season NOX bud

assumption that Selective Catalytic Reduction (SCR) technology is currently installed at Bay Shore Unit 4 in 2012. There is construction at the unit. Therefore, EPA is finalizing an increase to the state’s 2012 and 2014 annual NOX and ozone-season 

projected emissions without this unit operating a SCR. This results in a 2,218 ton increase to the state’s annual NOX budgets 

ton increase in the state’s ozone-season NOX budgets in 2012 and 2014. 

Table C.4.a.: Calculation to Determine Ohio Budget Adjustment - Assuming no SCR at Bay S

 A B C D Plant Unit 

Emissions from TR_Remedy Final_2012 (1000 tons) 

HI from TR_Remedy_Final_2012 (TBtu) 

Remedy Emission Rate from TR_Remedy_Final_2012 (lbs/MMBtu) 

Adjusted Emission Rate (lbs/MMBtu)

AdjuEmi

Calculation A*2/B D x Bay Shore 4 0.468366563 13.4995095 0.069 0.398 2.Bay Shore 4 0.203626114 5.86901984 0.069 0.398 1.
Columns A, B, and C show the NOX emissions, heat input, and emission rate from the TR_Remedy_Final_2012 mod

to be present the unit. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NOX policy rate

the September 1, 2010 TR Notice of Data Availability (NODA) (column D).43 This value reflects the NOX emission rate assu

Transport Rule as originally proposed, when EPA did not assume a SCR to be present at the unit. This value approximates th

unit at a cost threshold of $500/ton when no SCR is present at the unit. EPA multiplied this NOX rate by the remedy heat inp

a revised emissions projection for the unit (column E). The difference between this revised emission projection (no SCR assuRule remedy analysis emission projection (SCR assumed) determines the amount of the increase to the state’s annual NOX an

(column F). The first row shows the calculation for the annual NOx budget adjustment and the second row shows the calcula

adjustment. 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSAs for annual NOX and ozone-season NOX in Ohio remain at 2%. Along with revisions accounting for out-of-

Ohio presented below, the original and revised values for the state budgets, assurance levels, and new unit set-asides are desc

5) New York

EPA is finalizing, based on comments, an increase to New York’s 2012 and 2014 SO2 budgets to correct for the remo

DSI technology at the Dunkirk and Huntley facilities. As noted in the “Significant Contribution and State Emissions Budget

Transport Rule, EPA had received comment during the rule proposal noting that these facilities had DSI in place of the FGD 

adjusted the state budgets before finalizing the Transport Rule to reflect DSI technology. Because no verifiable removal rate technologies in the comment at this time, EPA assumed the default 70% removal rate used for new DSI. However, during th

Revisions Rule, a commenter noted that these units’ existing DSI systems are not capable of achieving such a rate. The commby newly available 2010 EIA 860 data providing a reported SO2 removal rate of 53% for the units. EPA has calculated a bud

SO2 budgets in 2012 and 2014 assuming an SO2 removal rate of 53% as opposed to the 70% rate previously assumed in the funits. 

43 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev4
Table C.5.a.: Calculation to Determine New York Budget Adjustment - Correcting for DSI Remo

 A B C D  Unit 

Removal Rate Assumed in TR_Remedy_Final_2012 

Emissions from TR_Remedy Final_2012 (1000 tons) 

Emissions assuming 70% removal (1000 tons) 

Emissions Assuming 53removal (100tons) 

Calculation B/(1-A)*.3 B/(1-A)*.47 C R Huntley Generating Station 67 92.3% 0.340946408 1.328362629 2.0811014C R Huntley Generating Station 68 92.3% 0.340946408 1.328362629 2.0811014Dunkirk Generating Station 3 95.9% 0.383454384 2.805763788 4.39569Dunkirk Generating Station 4 95.9% 0.38488252 2.81621356 4.412067Dunkirk Generating Station 1 70.0% 0.623572839 0.623572839 0.9769307Dunkirk Generating Station 2 70.0% 0.55670215 0.55670215 0.8721667Total 2.63050471 9.458977594 14.81906

Column A and B show the removal rate and corresponding emissions assumed in the initial TR_Final_Rule modeling

adjusted emissions assuming 70% removal efficiency that was assumed for the Final Transport Rule Budget determination. C

for these units assuming a 53% removal rate (as reported in the EIA 860 form for the units). Column E shows the net budget 

the 70% removal efficiency with a 53% removal efficiency for the DSI present at the facilities. This results in a 5,360 ton inc

for 2012 and 2014. 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSA for SO2 in New York remains at 2%. Along with revisions accounting for out-of-merit order dispatch at uni

below, the original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C

6) Kansas

EPA is finalizing, based on comment, an update to Kansas’s 2014 annual NOX budget to correct for the assumption t

decree emission rate and tonnage cap requirements begin in 2015, not 2014 as assumed in the final rule analysis. The final 2

applied SCR retrofit technology to some capacity at the Jeffrey Energy Center to comply with the 0.1 lb/MMBtu rate require
decree; however, because this rate requirement does not begin until 2015, EPA is assuming that the emission rate requiremenresult in any new controls until 2015 at the Jeffrey Energy Center. This revised assumption would, if examined in isolation, y

in projected annual NO

X emissions in Kansas in 2014, which would bring total projected NO

X emissions from covered EGUs 

exceeds the state’s 2012 budget. However, as explained in the final Transport Rule, “for any covered state whose emissions 

projected to increase from 2012 to 2014 under the relevant cost thresholds... EPA is finalizing that state’s 2014 emission budof the 2012 emission budget” (76 FR 48261). Therefore, EPA is increasing the 2014 Kansas NO

X budget by 5,154 tons so th

state’s 2012 budget following the methodology and rationale laid out in the final Transport Rule. 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSA for annual NOX in Kansas remains at 2%. Along with revisions accounting for out-of-merit order dispatch 

below, the original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C

7) Georgia

EPA is finalizing, based on comment, an update to Georgia’s 2014 SO2, annual NO

X, and ozone-season NO

X state bu

assumption in the final Transport Rule analysis that particular Georgia Multi-Pollutant State Rule control deadlines for FGD

Scherer, and Yates facilities would deliver emission reductions in 2014, whereas those reductions are in fact not required to Because these controls are not required by that state rule to operate in 2014, EPA is adjusting the 2014 budgets upwards to rcontrols at these units.44

44 EPA based these revisions on the schedule of retrofit deadlines that is most consistent with comments provided, which generally reflect

Multi-Pollutant State Rule as it existed when EPA finalized the Transport Rule in July of 2011. 
Table C.7.a.: Calculation to Determine Georgia SO2 Budget Adjustments - Assuming Revised Con

Dates 

SO2

A B C D 

2012 Emission Rate from TR_Remedy_Final (lbs/MMBtu) 

2014 Heat Input (TBtu) 

2014 Revised Emissions (1000 tons) 

2014 TR_Remedy_Final Emissions (1000 tons) 

NeAd(10

Calculation A x B Branch 1 0.92 16.50 7.60 1.85 Branch 2 0.92 20.06 9.24 2.25 Scherer 1 0.57 57.61 16.49 6.43 Yates 6 0.91 21.23 9.70 0.86 Yates 7 0.91 20.89 9.55 0.85 Total 

Table C.7.b.: Calculation to Determine Georgia NOX Budget Adjustments - Assuming Revised Co

Dates 

Annual NO

X

A B C D 

2012 Emission Rate from TR_Remedy_Final (lbs/MMBtu) 

2014 Heat Input (TBtu) 

2014 Revised Emissions (1000 tons) 

2014 TR_Remedy_Final Emissions (1000 tons) 

NeAd(10

Calculation A x B Branch 1 0.45 16.50 3.75 0.60 Branch 2 0.43 20.06 4.36 0.69 Scherer 1 0.15 57.61 4.20 2.02 Yates 6 0.26 21.23 2.80 0.73 Yates 7 0.28 20.89 2.88 0.75 Total 
Table C.7.c.: Calculation to Determine Georgia Ozone-Season NOX Budget Adjustments - Assumi

Control Start Dates 

 Ozone-Season NO

X

 A B C D 

2012 Emission Rate from TR_Remedy_Final (lbs/MMBtu) 

2014 Heat Input (TBtu) 

2014 Revised Emissions (1000 tons) 

2014 TR_Remedy_Final Emissions (1000 tons) 

NeAd(10

Calculation A x B Branch 1 0.45 7.19 1.63 0.26 Branch 2 0.43 8.74 1.90 0.30 Scherer 1 0.15 25.29 1.84 0.89 Yates 6 0.26 9.27 1.22 0.32 Yates 7 0.28 9.12 1.26 0.33 Total 

In each of the above tables, column A reflects the emission rate observed for that unit in the 2012 TR_Remedy_Final 

present. Column B reflects the heat input assumed in the 2014 TR_Remedy_Final analysis when a FGD or SCR was assum

multiplies the heat input by the uncontrolled emission rate to get the uncontrolled emission rate assumption for 2014. The duncontrolled emissions values (column C) and the controlled emissions value originally assumed (column D) results in the a

(column E). 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the meth

Rule, the NUSA for SO2 in Georgia remains at 2%. The original and revised values for the state budgets, assurance levels, an

described in the table below. 
Table C.7.d.: Impact of Georgia's Budget Revisions - Assuming Revised Control Start Da

 Program Budget 

Assurance Level 

Total 

Set-

% of 

Budget Tons 

% of 

Budge

2012 Before June Revisions Rule SO2 158,527 - - 2% 2012 After June Revisions Rule SO2 158,527 - - 2% 2014 Before June Revisions Rule SO2 95,231 118% 112,373 2% 2014 After June Revisions Rule SO2 135,565 118% 159,967 2% 2012 Before June Revisions Rule Annual NOX 62,010 - - 2% 2012 After June Revisions Rule Annual NOX 62,010 - - 2% 2014 Before June Revisions Rule Annual NOX 40,540 118% 47,837 2% 2014 After June Revisions Rule Annual NOX 53,738 118% 63,411 2% 2012 Before June Revisions Rule Ozone-Season NOX 27,944 - - 2% 2012 After June Revisions Rule Ozone-Season NOX 27,944 - - 2% 2014 Before June Revisions Rule Ozone-Season NOX 18,279 121% 22,118 2% 2014 After June Revisions Rule Ozone-Season NOX 24,041 121% 29,090 2% *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

8) Arkansas (NUSA)

Turk Unit 1 in Arkansas commences commercial operation on or after January 1, 2010. Such a date qualifies Turk U

by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the final Transport Rule. How

Rule, EPA did not recognize Turk Unit 1 as a new unit and therefore omitted its projected emissions in the determination of t

set-aside for Arkansas. Prior to this revision, in keeping with a revision demonstrated above and effected in the final revision

set at 5%, including the minimum 2% NUSA percentage plus a 3% state-specific percentage to account for other planned uni

calculation of the Arkansas ozone-season NOX new unit set-aside to reflect the “new unit” status of Turk Unit 1. Following t

45 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which 

added if the given state has projected emissions from “planned” new units (76 FR 48291). 
final Transport Rule, EPA has already recorded (i.e., distributed) allowances under the Federal Implementation Plan (FIP) fo

Therefore, this revision to the NUSA will be implemented beginning in 2014. 

The calculations to estimate 2020 ozone-season NOX Emissions from Turk Unit 1 are shown in the table below: 

Table C.8.a.: Calculation for Arkansas' Total Ozone-Season 

NOX Emissions from Turk Unit 146

A Capacity (MW) 600B Heat Rate (Btu/kWh) 8980

C NOX Emissions Rate (lbs/MMBtu) 0.05

D Capacity Factor 85%

E Ozone-Season Hours 3672

Total Ozone-Season NOX Emissions (tons) 

(A*D*B/1000*E*C/2000) 420

The calculations to quantify this revision are shown in the table below: 

Table C.8.b.: Calculation for Arkansas' NUSA 

A 

Projected 2020 Ozone-Season NOX Emissions from Turk Unit 

1 (tons) 420

B Arkansas 2014 Ozone-Season NOX State Budget (tons) 15,110C Turk's Emissions as a % of Arkansas State Budget (A/B) 3%D Previous Percentage for New Unit Set-Aside 5%E Total New Unit Set-Aside (C + D) 8%

EPA divided Turk Unit 1’s projected emissions into the state budget to derive the state-specific percentage increase f

Arkansas, which rounds to 3%. This value was added to the new unit set-aside percentage previously calculated for the final 

46 Projected 2020 ozone-season NOX emissions were estimated and the new unit set-aside was calculated using the method outlined in the 

48291) and the Technical Revisions to State Budgets and New Unit Set-Asides associated with the Final Rule. EPA used data provided b

plant assumptions. 
earlier in this document. The resulting new unit set-aside percentage for ozone-season NOX in Arkansas is 8%. This change 

or assurance level in any way. However, the new unit set-aside would change by the levels shown below.47

Table C.8.c: Impact of 2014 Ozone Season NOX NUSA revision for Arkansas 

New Unit SetAside 

Existing Unit Allocation Total 

2014 As Finalized in February Revisions Rule % 5% 95% 100% 2014 With June Rule Revision % 8% 92% 100% 2014 As Finalized in February Revisions Rule tons 752 14,285 15,037 2014 With June Rule Revision tons* 1,209 13,901 15,110 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

9) Louisiana (NUSA)

Washington Parish Energy Center Units CTG1, CTG2 and ST1 were included in the final Transport Rule NUSA calc

commence commercial operation on or after January 1, 2010. However, these units were never completed and will not be op

removing their projected emissions from calculations for the Louisiana ozone-season NOX NUSA. Prior to this revision, that 

including the minimum 2% NUSA percentage plus a 1% state-specific percentage to account for planned units.48 EPA is now 

47 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budge

allowance allocations associated with this revision, please see the document entitled “Final June Revisions Rule Unit-Level Allocations u

to this rulemaking. 

48 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which 

added if the given state has projected emissions from “planned” new units (76 FR 48291). 
Louisiana ozone-season NOX new unit set-aside to remove the projected emissions of these units that will not be commencin

take effect for Louisiana’s NUSA in 2012 and beyond.49

EPA subtracted the Washington Parish units’ projected emissions from the projected planned unit emissions for Loui

emissions were divided into the state budget to derive the revised state-specific percentage for the new unit set-aside in Louis

Therefore, the new unit set-aside percentage for ozone-season NOX in Louisiana is 2%, the base percentage for the new unit s

Table C.9.a.: Calculation for Louisiana's NUSA 

A Previously Calculated Total Planned Emissions (tons) B Projected 2020 Ozone-Season NOX Emissions from Washington Parish (tons) C Remaining Planned Emissions (A - B) D Louisiana Ozone Season NOX State Budget (tons) E Remaining Committed Emissions as a % of Arkansas State Budget (C/D) F Base percentage for new unit set-aside G Total New Unit Set-Aside (E + F\) 

This change does not impact the state budget or assurance level in any way. However, the new unit set-aside would 

below.50 EPA intends to record any additional 2012 and 2013 allocations to existing units due to this revision once this rule, 

Transport Rule, are legally effective. 

49 The originally projected emissions from Washington Parish Energy Center are no longer relevant to any of EPA’s emission projections 

to the Transport Rule, as all of its projected generation was offset in the final revisions rule by revised assumptions of increased generatio

near-term out-of-merit-order dispatch conditions.

50 The proposed decrease to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the s

unit allowance allocations associated with this revision, please see the document entitled “Final June Revisions Rule Unit-Level Allocatio

docket to this rulemaking. 
Table C.9.b: Impact of 2012 Ozone Season NOX NUSA revision for Louisiana 

New Unit SetAside Existing Unit Allocation T

2012 As Finalized in February Revisions Rule % 3% 97% 2012 With June Rule Revision % 2% 98% 2012 As Finalized in February Revisions Rule tons 523 17,503 12012 With June Rule Revision tons* 344 17,771 12014 As Finalized in February Revisions Rule % 3% 97% 2014 With June Rule Revision % 2% 98% 2014 As Finalized in February Revisions Rule tons 523 17,503 12014 With June Rule Revision tons* 344 17,771 1*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

10) Missouri (NUSA)

Iatan Unit 2 in Missouri commenced commercial operation on or after January 1, 2010. Such a date qualifies Iatan U

by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the final Transport Rule. HowRule, EPA did not recognize Iatan Unit 2 as a new unit and therefore omitted its projected emissions in the determination of t

season NOX new unit set-asides for Missouri. For the final Transport Rule and the Transport Rule Supplemental Notice of Fi

NUSAs were set at 2% for SO2, 3% for annual NOX and 3% for ozone-season NOX, including the minimum 2% NUSA perce

percentage for each budget.51 EPA is now revising the calculations of the Missouri new unit set-asides to reflect the “new un

Following the schedule established in the final Transport Rule, EPA has already recorded (i.e., distributed) allowances under Therefore, this revision to the NUSAs will be implemented beginning in 2013. 

51 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which 

added if the given state has projected emissions from “planned” new units (76 FR 48291). 
The calculations to quantify Projected 2020 Emissions from Turk Unit 1 are shown in the table below52: 

Table C.10.a.: Calculation for Missouri's NUSA 

SO2 NO

A Capacity (MW) 850 B Heat Rate (Btu/kWh) 9000 

C Emissions Rate (lbs/MMBtu) 0.06 

D Capacity Factor 85% 

E Ozone Season Hours 8760 

 Total Emissions (tons) (A*D*B/1000*E*C/2000) 1709 

EPA divided Iatan Unit 2’s projected emissions into the state budgets to derive the increases to the state-specific perc

asides in Missouri, which round to 1% for SO2, 3% for annual NOX and 3% for ozone-season NOX. These values were added 

new unit set-asides from the final Transport Rule and the Transport Rule Supplemental Notice of Final Rulemaking . The res

percentages in Missouri are 3% for SO2, 6% for annual NOX and 6% for ozone-season NOX. This change does not impact the 

in any way. However, the NUSAs would change by the levels shown below.53

52 Projected 2020 ozone-season NOX emissions were calculated using the method outlined in the final Transport Rule (76 FR 48291) and 

Budgets and New Unit Set-Asides associated with the Final Rule. EPA used data provided by the commenter, IPM model plant assumptifollowing: Robert Peltier, Plant of the Year: KCP&L’s Iatan 2 Earn’s POWER’s Highest Honor, Power Magazine, August 1, 2011, availa

<http://www.powermag.com/environmental/3882.html>.

53 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budge

allowance allocations associated with this revision, please see the document entitled “Final June Revisions Rule Unit-Level Allocations u

to this rulemaking. 
Table C.10.b: Impact of 2013 NUSA revisions for Missouri (tons) 

SO2 New 

Unit SetAside 

SO2 Existing 

Unit Allocation SO2 Total 

Annual NOX

New Unit Set-Aside 

Annual NOX

Existing Unit Allocation 

Annual NOX

Total 

OS NOX Ne

Unit Set-Asi

% As Finalized in February Final Revisions Rule 2% 98% 100% 3% 97% 100% 3% % With June Final Rule Revision 3% 97% 100% 6% 94% 100% 6% 2013 As Finalized in February Final Revisions Rule tons 4,149 203,317 207,466 1,571 50,803 52,374 683 2013 With June Final Rule Revision tons* 6,224 201,242 207,466 3,144 49,256 52,400 1,367 2014 As Finalized in February Final Revisions Rule tons 3,319 162,622 165,941 1,462 47,255 48,717 632 2014 With June Final Rule Revision tons* 4,978 160,963 165,941 2,925 45,818 48,743 1,266 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

11) Mississippi

EPA is finalizing, based on comments, an increase to Mississippi’s ozone season NOX budget in 2012 and 2014 to re

term operational constraints affecting a unit at the Moselle plant, based on information provided by the system operator demo

located in an out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-t

in recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below dTransport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at Moselle based on the ne

and regulation in the load pocket and the minimum operating constraint of a unit at Moselle.54 As discussed later in this sect

additional generation dispatched from this facility would offset generation that would otherwise come from combined cycle u

54 See Docket Nos. EPA-HQ-OAR-2009-0491-4763 and EPA-HQ-OAR-2009-0491-4746. 
revision to Mississippi’s state budget is based on the net change to projected emissions taking that offsetting factor into accou

changes on the state’s ozone season NO

X budget is a 115 ton increase. 

The calculations of the increase in ozone season NO

X emissions due to out-of-merit-order dispatch at Moselle is show

the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, and emissio

database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The additional g

order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the number of (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rat

additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat inpu

rate. 

Table C.11.a.: Calculation to Determine Mississippi Ozone Season NOX Budget Revisions - Assuming out-of-meri

Moselle 

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/ kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio

Calculation C*H*3.6Moselle 2070_B_2 59 0 12878 0 0.258 34% 73*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table C.11.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Mississippi combined cycle units, shown in these calculations as a representative unit with a heat rate (column B

equal to the generation-weighted average of Mississippi combined cycle units.55 The ozone season NO

X emissions associated 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

55 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
Table C.11.b.: Calculation of Emissions from Displaced Generation at Mississippi Combined Cy

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BOzone Season 74 7,570 0.026054137 

The total revision to Mississippi’s state budget due to the out-of-merit-order dispatch is calculated in Table C.11.c. T

the generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to t

generation (row A) to determine the net emission budget changes for Mississippi (row C). 

Table C.11.c.: Calculation to Determine Net Mississippi 

Ozone Season NOX Budget Revisions 

A

Additional Emissions Due to Out-Of-Order-Merit Dispatch 123

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 7

C

Net Change in Emission budget For Mississippi (A-B) 115
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are de

Table C.11.d.: Impact of Mississippi Ozone-Season NOX Budget Revisions – Assuming 

Out-of-Merit-Order Dispatch at Three Facilities (tons) 

 Budget

Assurance Level 

Total New 

Unit SetAside* 

% of 

Budget Tons 

% of 

Budget Tons

2012 Before June Revisions Rule 12,314 - - 2% 246 2012 After June Revisions Rule 12,429 - - 2% 249 2014 Before June Revisions Rule 12,314 12,314 151,634,596 2% 246 2014 After June Revisions Rule 12,429 12,429 154,480,041 2% 249 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

12) Arkansas

EPA is finalizing, based on comments, an increase to Arkansas’s ozone season NOX budget in 2012 and 2014 to refle

operational constraints affecting units at the McClellan plant, based on information provided by the system operator demonst

Region is an out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-tin recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below dTransport Rule programs. Specifically, EPA is assuming additional generation will be dispatched the McClellan plant based 

representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispa

provided by Entergy.56 As discussed later in this section, EPA assumes that the additional generation dispatched from this fa

that would otherwise come from combined cycle units within the state, and the revision to Arkansas’s state budget is based o

emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NOX budget 

56 See EPA-HQ-OAR-2009-0491-4820 and Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transm

Entergy” in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4729). 
The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at McClellan is sh

unit, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, and em

database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The additional g

order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the number of 

(column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat ratadditional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat inpu

rate. 

Table C.12.a.: Calculation to Determine Arkansas Ozone Season NOX Budget Revisions - Assuming out-of-merit-or

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio

Calculation C*H*3.6McClellan 203_B_01 134 0 10901 0 0.20229893 16% 78*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table C.12.b., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Arkansas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) 

equal to the generation-weighted average of Arkansas combined cycle units.57 The ozone season NOX emissions associated w

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

57 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
Table C.12.b.: Calculation of Emissions from Displaced Generation at Arkansas Combined Cyc

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BOzone Season 79 7,549 0.044891435 

The total revision to Arkansas’s state budget due to the out-of-merit-order dispatch is calculated in Table C.12.c. The 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Arkansas (row C). 

Table C.12.c.: Calculation to Determine Net Arkansas 

Ozone Season NOX Budget Revisions (tons) 

A

Additional Emissions Due to Out-Of-Order-Merit Dispatch 87

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 13

C

Net Change in Emission budget For Arkansas (A-B) 73
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described 

Table C.12.d.: Impact of Arkansas Ozone-Season NOX Budget Revisions – 

Assuming Out-of-Merit-Order Dispatch at McClellan (tons) 

 Budget

Assurance 

Level 

Total New 

Unit SetAside* 

% of 

Budget Tons 

% of 

Budget Tons 

2012 Before June Revisions Rule 15,037 - - 5% 752 2012 After June Revisions Rule 15,110 - - 5% 756 2014 Before June Revisions Rule 15,037 121% 18,195 5% 752 2014 After June Revisions Rule 15,110 121% 18,283 8% 1,209*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

13) Texas

EPA is finalizing, based on comments, an increase to Texas’s annual and ozone season NOX budget in 2012 and 201

near-term operational constraints affecting units at seven plants, based on information provided by the system operator demo

out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local con

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the im

Rule programs. Specifically, EPA is assuming additional generation will be dispatched at seven plants (Jones, Moore CountLone Star, and Knox Lee) based on the average capacity factor representing the frequency the unit is projected to be called to 

derived from immediate-term dispatch modeling projections provided by SPS58 and AEP.59 As discussed later in this section

58 See EPA-HQ-OAR-2009-0491-4752 and the document “Clarification of comments originally filed on the TR Revisions Rule by SPS” 

(Docket No. EPA-HQ-OAR-2009-0491-4868). 
additional generation dispatched from these seven facilities would offset generation that would otherwise come from combin

and the revision to Texas’s state budget is based on the net change to projected emissions taking that offsetting factor into acc

changes on the state’s annual NO

X and ozone season NO

X budgets are 2,731 and 1,142 ton increases, respectively. 

The calculations of the increase in annual NO

X and ozone season NO

X emissions due to out-of-merit-order dispatch a

Tables C.13.a. and C.13.b. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Fi

from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average ouis shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, 

capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by 

generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generatimultiplying the additional heat input by the unit’s NO

X emission rate. 

Table C.13.a.: Calculation to Determine Texas Annual NOX Budget Revisions - Assuming out-of-merit-order d

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual NOX

Rate (lbs/MMBtu) 

Annual Average OutOf-MeritOrder Capacity Factor 

AdditionaAnnual Generatio

Calculation C*H*8.7Jones 3482_B _151B 243 0.17811372 11109 283.774892 0.11 41% 881.00 Jones 3482_B _152B 243 0.119198228 10245 283.774892 0.08 50% 1069.0Moore 3483_B 48 0 14075 0 0.12 20% 82.00 

59 See EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed o

found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4867). 
County _3 

Nichols 3484_B _141B 107 0.074400425 9983 125.737030 0.12 29% 276.00 Nichols 3484_B _142B 106 0.07774879 10450 124.561917 0.12 32% 296.00 Nichols 3484_B _143B 244 0 11682 0 0.16 27% 572.00 Plant X 3485_B _111B 48 0 16243 0 0.32 23% 98.00 Plant X 3485_B _112B 102 0 13226 0 0.08 18% 162.00 Plant X 3485_B _113B 103 0 11484 0 0.17 20% 182.00 Plant X 3485_B _114B 189 0 10841 0 0.10 53% 881.00 Knox Lee 3476_B _2 25.0 0 14500 0 0.102 2% 4.80 Knox Lee 3476_B _3 25.0 0 14500 0 0.123 3% 6.68 Knox Lee 3476_B _4 77.0 0 14933 0 0.311 1% 9.84 Knox Lee 3476_B _5 343 0 11669 0 0.174 4% 105.53 
Wilkes 

3478_B_1 175 0 12904 0 0.136 11% 176

Lone Star 

3477_B_1 50.0 0 14546 0 0.230 5% 22

Total 4,824

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in year; that factor is divided by 1,000 to yield unit

Table C.13.b.: Calculation to Determine Texas Ozone-Season NOX Budget Revisions - Assuming out-of-merit-orde

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio

Calculation C*H*3.6Jones 

3482_B_151B 243 0.17811372 11109 283.774892 0.11 31% 273

Jones 

3482_B_152B 243 0.119198228 10245 283.774892 0.08 26% 228

Moore County 

3483_B_3 48 0 14075 0 0.12 47% 82

Nichols 

3484_B_141B 107 0.074400425 9983 125.737030 0.12 17% 65

Nichols 

3484_B_142B 106 0.07774879 10450 124.561918 0.12 17% 68
Nichols 

3484_B_143B 244 0 11682 0 0.16 32% 288

Plant X 

3485_B_111B 48 0 16243 0 0.32 30% 52

Plant X 

3485_B_112B 102 0 13226 0 0.08 23% 85

Plant X 

3485_B_113B 103 0 11484 0 0.17 30% 112

Plant X 

3485_B_114B 189 0 10841 0 0.10 55% 384

Knox Lee 

3476_B_2 25.0 0 14500 0 0.102 5% 4

Knox Lee 

3476_B_3 25.0 0 14500 0 0.123 7% 6

Knox Lee 

3476_B_4 77.0 0 14933 0 0.311 3% 7

Knox Lee 

3476_B_5 343 0 11669 0 0.174 4% 46

Wilkes 

3478_B_1 175 0 12904 0 0.136 10% 66

Lone Star 

3477_B_1 50.0 0 14546 0 0.230 12% 22

Total 1,791
*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table C.13.c., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Texas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) an

equal to the generation-weighted average of Texas combined cycle units.60 The ozone season NOX emissions associated with 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

Table C.13.c.: Calculation of Emissions from Displaced Generation at Texas 

Combined Cycle Units 

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission 

Rate (lbs/MMBTU)

Displaced 

NOX

Emissions (tons) 

Calculation A*B*C/2000 Annual NOX 4,825 7,405 0.031895983 570 Ozone Season NOX 1,791 7,464 0.033113058 221 

The total revision to Texas’s state budget due to the out-of-merit-order dispatch is calculated in Table C.13.d. The em

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Texas (row C). 

Table C.13.d.: Calculation to Determine Net Texas Annual and Ozone Season NOX

Budget Revisions (tons) 

Annual NOX Ozone Season NOX

60 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
A 

Additional Emissions Due to Out-Of-Order-Merit Dispatch 3,301 1364 

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 570 221 

C 

Net Change in Emission budget For Texas (A-B) 2,731 1,142 

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described 

Table C.13.e.: Impact of Texas Budget Revisions – Assuming Removed FGDs and Revised FGD C

Certain Units, Revised NUSAs for Oak Grove 2, and Out-of-Merit-Order Dispatch at Two Facili

 Program Budget 

Assurance Level 

Total 

Set

% of 

Budget Tons 

% of 

Budg

2012 Before June Revisions Rule SO2 294,471 - - 5% 2012 After June Revisions Rule SO2 294,471 - - 5% 2014 Before June Revisions Rule SO2 294,471 118% 347,476 5% 2014 After June Revisions Rule SO2 294,471 118% 347,476 5% 2012 Before June Revisions Rule Annual NOX 134,970 - - 4% 2012 After June Revisions Rule Annual NOX 137,701 - - 4% 2014 Before June Revisions Rule Annual NOX 134,970 118% 159,265 4% 2014 After June Revisions Rule Annual NOX 137,701 118% 162,487 4% 2012 Before June Revisions Rule Ozone-Season NOX 64,418 - - 4% 2012 After June Revisions Rule Ozone-Season NOX 65,560 - - 4% 2014 Before June Revisions Rule Ozone-Season NOX 64,418 121% 77,946 4% 2014 After June Revisions Rule Ozone-Season NOX 65,560 121% 79,328 4% *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

14) Kansas

EPA is finalizing, based on comments, an increase to Kansas’s SO2 and NOX budgets in 2012 and 2014 to reflect the 

operational constraints affecting a unit at the Quindaro plant, based on information provided by the system operator demonstr

out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local con

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the im

Rule programs. Specifically, EPA is assuming additional generation will be dispatched Quindaro unit 1 based on the annual 

representing the frequency the unit is projected to be called to operate out-of-merit-order, provided in comments from Kansa

Utilities.61 In the model run TR_Remedy Final_2012, this unit ran at approximately a 55% annual capacity factor. KCBPU’s 

must operate at an average annual capacity factor of 75% to serve its load. Therefore, the difference of 20% is being conside

in this case. As discussed later in this section, EPA assumes that the additional generation dispatched from this facility would otherwise come from similarly-positioned coal-fired units within the state, and the revision to Kansas’s state budget is based emissions taking that offsetting factor into account. The net impact of these changes on the state’s SO2 and annual NOX budg

increases, respectively. 

The calculations of the increase in SO2 and annual NOX emissions due to out-of-merit-order dispatch at Quindaro un

and C.14.b. For the unit, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy 

from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in colum

for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, an

ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the addition

emission rate. 

61 See EPA-HQ-OAR-2009-0491-4779 and the document “Clarification of comments originally filed on the TR Revisions Rule by KC B

docket (Docket No. EPA-HQ-OAR-2009-0491-4871). 
Table C.14.a.: Calculation to Determine Kansas SO2 Budget Revisions - Assuming out-of-merit-order dispatc

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual 

SO2Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual SO2

Rate (lbs/MMBtu) 

Annual Average OutOf-MeritOrder Capacity Factor 

AdditionaAnnual Generatio

Calculation C*H*8.7Quindaro 1295_B_1 72 1.170152332 11673 345.6701925 0.579999983 33.8% 212.87 *The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the year; that factor is divided by 1,000 to yield 

Table C.14.b.: Calculation to Determine Kansas Annual NOX Budget Revisions - Assuming out-of-merit-order dis

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual NOX

Rate (lbs/MMBtu) 

Annual Average OutOf-MeritOrder Capacity Factor 

AdditionaAnnual Generatio

Calculation C*H*3.6Quindaro 

1295_B_1 72 1.355762723 11673 345.670193 0.67182472 33.8% 212

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table C.14.c., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at other Kansas coal units, shown in these calculations as a representative unit with a heat rate (column B) and em

the generation-weighted average of Kansas coal units.62 The ozone season NOX emissions associated with the displaced gene

calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative coal uni

62 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
coal-fired generation to offset the additional generation assumed now to occur at Quindaro unit 1 because it is reasonable to a

generation at Quindaro unit 1 would displace similarly-positioned baseload coal-fired generation previously projected to mee

Table C.14.c.: Calculation of Emissions from Displaced Generation at Kansas Coal Unit

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

Displaced Generation Emission Rate (lbs/MMBTU) 

Displaced Emissions (tons) 

Calculation A*B*C/20SO2 213 10,707 0.23598 269 Annual NOX 213 10,707 0.170752 195 

The total revision to Kansas’s state budget due to the out-of-merit-order dispatch is calculated in Table C.14.d. The e

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Kansas (row C). 

Table C.14.d.: Calculation to Determine Net Kansas SO2 and Annual NOXNOX Budget 

Revisions (tons) 

2012 2014 

SO2

Annual 

NOX SO2

Annua

NOX

A 

Emissions Due to Out-Of-MeritOrder Generation 721 835 721 835 

B 

Displaced Emissions from Out-OfMerit-Order Generation at Quindaro 269 195 269 195 

C 

Net Budget Revisions for Kansas (A-B) 452 640 452 640 

63 In addition, whereas EPA has made similar revisions affecting oil/gas steam units to other state budgets by offsetting previously proje

cycle generation, there are no gas‐fired combined cycles in the state of Kansas that could serve as candidates for this calculation. EPA b

demonstrated above, using representative coal‐fired generation as a broad match for the dispatch characteristics of the assumed increa

at Quindaro unit 1, maintains a consistent approach with the other revisions of this type made to Transport Rule state budgets.
The total budget revisions for Kansas are summarized below in Table C.14.e. 

Table C.14.e.: Total Budget Revisions for Kansas 

Budget Year

Revisions due to 

Out-of-MeritOrder Dispatch Revisions due to Unit Controls Total Change 

SO2 2012 452 -- 452 SO2 2014 452 -- 452 Annual NOX 2012 640 -- 640 Annual NOX 2014 640 5,154 5,794 

The original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C.14.f.

Table C.14.f.: Impact of Kansas Budget Revisions – for Out-Of-Merit-Order Dispatch and 

Controls 

 Program Budget 

Assurance Level

Total New 

Set-As

% of 

Budget Tons 

% of 

Budget 

2012 Before June Revisions Rule SO2 41,528 - - 2% 2012 After June Revisions Rule SO2 41,980 - - 2% 2014 Before June Revisions Rule SO2 41,528 118% 49,003 2% 2014 After June Revisions Rule SO2 41,980 118% 49,536 2% 2012 Before June Revisions Rule Annual NOX 30,714 - - 2% 2012 After June Revisions Rule Annual NOX 31,354 - - 2% 2014 Before June Revisions Rule Annual NOX 25,560 118% 30,161 2% 2014 After June Revisions Rule Annual NOX 31,354 118% 36,998 2% *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 
15) Missouri

EPA is finalizing, based on comments, an increase to Missouri’s annual and ozone season NOX budget in 2012 and 2014 to r

term operational constraints affecting units at four plants, based on information provided by the system operator demonstratin

dispatch out-of-merit-order to provide voltage support and regulation. EPA's analysis in the final Transport Rule did not inco

local conditions described in recently submitted documentation that appear likely to necessitate non-economic generation at tthe implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched 

Greenwood, Ralph Green, and South Harper) based on the average capacity factor representing the frequency the unit has rec

out of merit order, calculated from dispatch logbook data provided by KCPL.64 As discussed later in this section, EPA assum

generation dispatched from these four facilities would offset generation that would otherwise come from combined cycle uni

revision to Missouri’s state budget is based on the net change to projected emissions taking that offsetting factor into accountchanges on the state’s annual and ozone season NOX budget are 26 ton increases each.

The calculations of the increase in annual and ozone season NOX emissions due to out-of-merit-order dispatch at the 

Tables C.15.a. and C.15.b. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Fi

from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average ouis shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, 

capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generati

multiplying the additional heat input by the unit’s NOX emission rate. 

64 See EPA-HQ-OAR-2009-0491-4826 and the document “Clarification of comments originally filed on the TR Revisions Rule by KCPL

docket (Docket No. EPA-HQ-OAR-2009-0491-4866). 
Table C.15.a.: Calculation to Determine Missouri Annual NOX Budget Revisions - Assuming out-of-merit-order 

A B C D E F G H I Plant Name Unique Id 

Capacity 

(MW) 

2012 Annual NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual NOX

Rate (lbs/MMBtu) 

Annual Average OutOf-MeritOrder Capacity Factor 

AdditionaAnnual Generatio

Calculation C*H*8.7Hawthorn 2079_G_7 77 0 13180 0 0.03072543 0.06% 0Hawthorn 2079_G_8 77 0 16770 0 0.03190992 0.14% 0Greenwood 6074_G_1 58 0 13300 0 0.50105250 0.31% 1Greenwood 6074_G_2 58 0 13300 0 0.50105250 0.23% 1Greenwood 6074_G_3 58 0 13300 0 0.50105250 0.35% 1Greenwood 6074_G_4 58 0 13300 0 0.50105250 0.28% 1Ralph Green 2092_G_3 71 0 14322 0 0.50105250 0.02% 0South Harper 

56151_G_GT1 105 0 15250 0 0.05518069 0.54% 4

South Harper 

56151_G_GT2 105 0 15082 0 0.05490044 0.81% 7

South Harper 

56151_G_GT3 105 0 15250 0 0.05578315 0.48% 4

Total 24

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in year; that factor is divided by 1,000 to yield uni
Table C.15.b.: Calculation to Determine Missouri Ozone Season NOX Budget Revisions - Assuming out-of-merit-or

A B C D E F G H I Plant Name Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio

Calculation C*H*3.7Hawthorn 2079_G_7 77 0 13180 0 0.03072543 0.14% 0Hawthorn 2079_G_8 77 0 16770 0 0.03190992 0.34% 0Greenwood 6074_G_1 58 0 13300 0 0.50105250 0.73% 1Greenwood 6074_G_2 58 0 13300 0 0.50105250 0.54% 1Greenwood 6074_G_3 58 0 13300 0 0.50105250 0.83% 1Greenwood 6074_G_4 58 0 13300 0 0.50105250 0.66% 1Ralph Green 2092_G_3 71 0 14322 0 0.50105250 0.05% 0South Harper 

56151_G_GT1 105 0 15250 0 0.05518069 1.30% 4

South Harper 

56151_G_GT2 105 0 15082 0 0.05490044 1.94% 7

South Harper 

56151_G_GT3 105 0 15250 0 0.05578315 1.14% 4

Total 24

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table C.15.c., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Missouri combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) 

equal to the generation-weighted average of Missouri combined cycle units.65 The ozone season NO

X emissions associated w

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

65 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
Table C.15.c.: Calculation of Emissions from Displaced Generation at 

Missouri Combined Cycle Units 

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate (lbs/MMBTU)

Displaced NOXEmissions (tons) 

Calculation A*B*C/2000 Annual 24 8,049 0.018330584 2 Ozone Season 24 8,079 0.018315387 2 

The total revision to Missouri’s state budget due to the out-of-merit-order dispatch is calculated in Table C.15.d. The 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Missouri (row C). 

Table C.15.d.: Calculation to Determine Net Missouri and Ozone Season NOX

Budget Revisions (tons) 

2012 2014 

Annual 

NOX

Ozone 

Season 

NOX

Annual 

NOX

Ozone 

Season 

NOX

A 

Emissions Due to Out-Of-MeritOrder Generation 28 28 28 28 

B 

Displaced Emissions from Out-OfMerit-Order Generation 2 2 2 2 

C 

Net Budget Revisions for Missouri (A-B) 26 26 26 26 
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are de

includes the adjustments to Missouri’s new unit set aside described in section 10. 

Table C.15.e.: Impact of Missouri Budget Revisions for Out-Of-Merit-Order Dispatch and New Un

 Program Budget 

Assurance Level Total New 

% of 

Budget Tons % of Budg

2012 Before June Revisions Rule SO2 207,466 - - 2% 2012 After June Revisions Rule SO2 207,466 - - 2% 2013 Before June Revisions Rule SO2 207,466 - - 2% 2013 After June Revisions Rule SO2 207,466 - - 3% 2014 Before June Revisions Rule SO2 165,941 118% 195,810 2% 2014 After June Revisions Rule SO2 165,941 118% 195,810 3% 2012 Before June Revisions Rule Annual NOX 52,374 - - 3% 2012 After June Revisions Rule Annual NOX 52,400 - - 3% 2013 Before June Revisions Rule Annual NOX 52,374 - - 3% 2013 After June Revisions Rule Annual NOX 52,400 - - 6% 2014 Before June Revisions Rule Annual NOX 48,717 118% 57,486 3% 2014 After June Revisions Rule Annual NOX 48,743 118% 57,517 6% 2012 Before June Revisions Rule Ozone-Season NOX 22,762 - - 3% 2012 After June Revisions Rule Ozone-Season NOX 22,788 - - 3% 2013 Before June Revisions Rule Ozone-Season NOX 22,762 - - 3% 2013 After June Revisions Rule Ozone-Season NOX 22,788 - - 6% 2014 Before June Revisions Rule Ozone-Season NOX 21,073 121% 25,498 3% 2014 After June Revisions Rule Ozone-Season NOX 21,099 121% 25,530 6% *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 
16) Oklahoma 

EPA is finalizing, based on comments, an increase to Oklahoma’s ozone season NOX budget in 2013 and 2014 to ref

operational constraints affecting units at four plants, based on information provided by the system operator demonstrating the

order dispatch area. These changes do not apply to Oklahoma’s 2012 budget because similar changes were already made to t

2012, as described in the Technical Support Document “Determination of State Budgets for the Final Ozone Supplemental of 

analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently submitted dto necessitate non-economic generation at the units displayed below during the implementation of the Transport Rule program

assuming additional generation will be dispatched at four plants (Northeastern, Riverside , Southwestern, and Tulsa) based on representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispaprovided by AEP.67 As discussed later in this section, EPA assumes that the additional generation dispatched from these fac

that would otherwise come from combined cycle units within the state, and the revision to Oklahoma’s state budget is based emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NOX budget 

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at these facilities 

each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation 

and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor 

additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-ord

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the increm

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by mu

input by the unit’s NOX emission rate. 

66 See EPA-HQ-OAR-2009-0491-485, pg 5-7. 67 See EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed o

found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4867). 
Table C.16.a.: Calculation to Determine Oklahoma Ozone Season NOX Budget Revisions - Assuming Out-of-Merit-Or

A B C D E F G H I Plant Name Unique Id 

Capacity 

(MW)

2012 Ozone Season NOX

Emissions from TR_ Remedy Final_ 2012 (1000 tons) 

Heat Rate (BTU/ kWh) 

Ozone Season Generation from TR_ Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average Out-OfMeritOrder Capacity Factor 

Additional Ozone Season Generation* 

Calculation C*H*3.672 Northeastern 2963_B_3302 480 0 10442 0 0.396 17.1% 301.0Riverside 4940_B_1502 459 0 11094 0 0.226 8.2% 137.7Southwestern 

2964_B_801N 40.0 0 20500 0 0.251 0.7% 1.0

Southwestern 2964_B_801S 40.0 0 20500 0 0.206 0.7% 1.0Southwestern 2964_B_8002 80.0 0 11900 0 0.326 2.1% 6.2Southwestern 2964_B_8003 311 0 11611 0 0.436 1.6% 17.7Tulsa 2965_B_1402 165 0 14213 0 0.182 1.7% 10.3Tulsa 2965_B_1403 85.0 0 11163 0 0.276 1.6% 4.8Tulsa 2965_B_1404 165 0 13144 0 0.188 5.8% 35.0

Total 515.0

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to y

As calculated in Table C.16.b., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Oklahoma combined cycle units, shown in these calculations as a representative unit with a heat rate (column B
equal to the generation-weighted average of Oklahoma combined cycle units.68 The ozone season NOX emissions associated 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

Table C.16.b.: Calculation of Emissions from Displaced Generation at Oklahoma Combined Cy

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BOzone Season 515 7,713 0.031566434 

The total revision to Oklahoma’s state budget due to the out-of-merit-order dispatch is calculated in Table C.16.c. Th

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Oklahoma (row C). 

Table C.16.c.: Calculation to Determine Net Oklahoma 

Ozone Season NOX Budget Revisions (tons) 

A

Additional Emissions Due to Out-Of-Order-Merit Dispatch 921

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 63

C

Net Change in Emission budget For Oklahoma (A-B) 859

68 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described 

Table C.16.d.: Impact of Oklahoma Ozone-Season NOX Budget Revisions – Assuming 

Out-of-Merit-Order Dispatch at Three Facilities (tons) 

 Budget

Assurance 

Level 

Total New 

Unit SetAside* 

% of 

Budget Tons 

% of 

Budget Tons 

2012 Before June Revisions Rule 36,567 - - 2% 731 2012 After June Revisions Rule 36,567 - - 2% 731 2013 Before June Revisions Rule 21,835 - - 2% 437 2013 After June Revisions Rule 22,694 - - 2% 454 2014 Before June Revisions Rule 21,835 121% 26,420 2% 437 2014 After June Revisions Rule 22,694 121% 27,460 2% 454 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

17) Louisiana 

EPA is finalizing, based on comments, an increase to Louisiana’s ozone season NOX budget in 2012 and 2014 to refl

operational constraints affecting units at two plants, based on information provided by the system operator demonstrating the

order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions descrdocumentation that appear likely to necessitate non-economic generation at the units displayed below during the implementaprograms. Specifically, EPA is assuming additional generation will be dispatched at two plants based on the average capacitfrequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispatch modeling pro

As discussed later in this section, EPA assumes that the additional generation dispatched from these facilities would offset ge

69 See EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed o

found in the Transport Rule Docket (Docket No. EPA-HQ-OAR-2009-0491-4867). 
come from combined cycle units within the state, and the revision to Louisiana’s state budget is based on the net change to pr

offsetting factor into account. The net impact of these changes on the state’s ozone season NO

X budget is a 89 ton increase. 

The calculations of the increase in ozone season NO

X emissions due to out-of-merit-order dispatch at these facilities 

each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation 

and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor 

additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-ord

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the increm

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by mu

input by the unit’s NO

X emission rate. 

Table C.17.a.: Calculation to Determine Louisiana Ozone Season NOX Budget Revisions - Assuming out-of-merit-or

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio

Calculation C*H*3.6J. Lamar Stall Unit at Arsenal Hill 

1416_B_5A 110 0 15,702 0 0.092 3% 11.82 

Lieberman 

1417_B_1 25.0 0 14,983 0 0.420 5% 4.20 

Lieberman 

1417_B_2 25.0 0 14,546 0 0.420 6% 5.41 

Lieberman 

1417_B_3 111 0 12,334 0 0.124 11% 46.52 

Lieberman

1417_B_4 109

0 12,791

0 0.132 8% 32.14 

Total 100

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 
As calculated in Table C.17.b., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Louisiana combined cycle units, shown in these calculations as a representative unit with a heat rate (column Bequal to the generation-weighted average of Louisiana combined cycle units.70 The ozone season NOX emissions associated w

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre

Table C.17.b.: Calculation of Emissions from Displaced Generation at Louisiana Combined Cyc

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

NOX Emission Rate 

(lbs/MMBTU) 

Displaced N

(tons) 

Calculation A*BOzone Season 100 7,480 0.031765081 

The total revision to Louisiana’s state budget due to the out-of-merit-order dispatch is calculated in Table C.17.c. Th

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Louisiana (row C). 

Table C.17.c.: Calculation to Determine Net Louisiana 

Ozone Season NOX Budget Revisions (tons) 

A

Additional Emissions Due to Out-Of-Order-Merit Dispatch 101

B 

Displaced Emissions From Out-Of-Order-Merit Dispatch 12

C

Net Change in Emission budget For Louisiana (A-B) 89

70 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are de

Table C.17.d.: Impact of Louisiana Ozone-Season NOX Budget Revisions – Assuming 

Out-of-Merit-Order Dispatch at Three Facilities (tons) 

 Budget

Assurance 

Level 

Total New 

Unit SetAside* 

% of 

Budget Tons 

% of 

Budget Tons

2012 Before June Revisions Rule 18,026 - - 3% 541 2012 After June Revisions Rule 18,115 - - 2% 362 2014 Before June Revisions Rule 18,026 121% 21,811 3% 541 2014 After June Revisions Rule 18,115 121% 21,919 2% 362 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 

18) Ohio

EPA is finalizing, based on comments, an increase to Ohio’s SO2, annual NOX, and ozone season NOX budget in 201

assumption of near-term operational constraints affecting Muskingum River unit 1, based on information provided by the sys

plant operates out-of-merit-order. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local cosubmitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the im

Rule programs. EPA is assuming additional generation will be dispatched from Muskingum River unit 1 based on operationa

AEP.71 As discussed later in this section, EPA assumes that the additional generation dispatched from this facilities would of

otherwise come from combined cycle units within the state, and the revision to Ohio’s state budget is based on the net change that offsetting factor into account. The net impact of these changes on the state’s SO2, annual NOX, and ozone season NOX b

and 247 ton increases, respectively. 

71 EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed on th

found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4867). 
The calculations of the increase in SO2, annual NOX, and ozone season NOX emissions due to out-of-merit-order disp

Tables C.18.a., C.18.b., and C.18.c. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Regeneration from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The capacity factor is shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplyin

of-merit-order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required wa

incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-oby multiplying the additional heat input by the unit’s NOX emission rate. 

Table C.18.a.: Calculation to Determine Ohio SO2 Budget Revisions - Assuming out-of-merit-order dispatch 

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual 

SO2

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual SO2

Rate (lbs/MMBtu) 

Annual Average OutOf-MeritOrder Capacity Factor 

AdditionaAnnual Generatio

Calculation C*H*8.7Muskingum River 

2872_B_1 190 0 10416 0 4.36 14% 227

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8,760 hours of possible operation in the year; that factor is divided by 1,000 to yield 

**SO2 rates were derived assuming a similar grade of coal as was used by comparable units in IPM in that region of Ohio and the SO2 content of coal in chapter 8 of th

SO2 rates are similar to historic rates at these units.
Table C.18.b.: Calculation to Determine Ohio Annual NOX Budget Revisions - Assuming out-of-merit-order dispatch 

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual NOX

Rate (lbs/MMBtu) 

Annual Average OutOf-MeritOrder Capacity Factor 

AdditionaAnnual Generatio

Calculation C*H*8.7Muskingum River 

2872_B_1 190 0 10416 0 0.46 14% 227

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the year; that factor is divided by 1,000 to yield 

Table C.18.c.: Calculation to Determine Ohio Ozone-Season NOX Budget Revisions - Assuming out-of-merit-order di

plants 

A B C D E F G H I Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average OutOf-MeritOrder Capacity Factor 

AdditionaOzone Season Generatio

Calculation C*H*3.6Muskingum River 

2872_B_1 190 0 10416 0 0.46 15% 106

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 

As calculated in Table C.18.d., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at Ohio combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and 
to the generation-weighted average of Ohio combined cycle units.72 The ozone season NOX emissions associated with the dis

were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative co

Table C.18.d.: Calculation of Emissions from Displaced Generation at Ohio 

Combined Cycle Units 

A B C 

D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

Emission Rate (lbs/MMBTU)

Displaced Emissions (tons) 

Calculation A*B*C/2000 SO2 227 7,191 0 0 Annual NOX 227 7,191 0.023597394 19 Ozone Season NOX 107 7,265 0.026009641 10 

The total revision to Ohio’s state budget due to the out-of-merit-order dispatch is calculated in Table C.18.e. The em

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for Ohio (row C). 

72 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
Table C.18.e.: Calculation to Determine Net Ohio SO2, Annual NOX, and Ozone 

Season NOX Budget Revisions (tons) 

2012 2014 

SO2

Annual 

NOX

Ozone 

Season 

NOX SO2

Annual 

NOX

Ozone 

Season 

NOX

A 

Additional Emissions Due to Out-Of-MeritOrder Generation 5,163 547 257 5,163 547 257

B 

Displaced Emissions from Out-Of-MeritOrder Generation 0 19 10 0 19 10

C 

Net Budget Revisions for Ohio (A-B) 5,163 528 247 5,163 528 247

The total revisions to Ohio’s budgets as a result of control and out-of-merit-order dispatch revisions are summarized below in 

Table C.18.f.: Total Budget Revisions for Ohio (tons) 

Budget Year

Revisions due to 

Out-of-MeritOrder Dispatch Revisions Due to Unit Controls Total Change 

SO2 2012 5,163 5,163SO2 2014 5,163 5,163Annual NOX 2012 547 2,218 2,765Annual NOX 2014 547 2,218 2,765Ozone Season NOX 2012 257 964 1,221Ozone Season NOX 2014 257 964 1,221
The original and revised values for the state SO2, annual NOX, and ozone season NOX budgets, assurance levels, and 

described in Table C.18.g. 

Table C.18.g.: Impact of Ohio Budget Revisions for Out-Of-Merit-Order Dispatch and Control R

 Program Budget 

Assurance Level 

% of 

Budget Tons 

% 

Bu

2012 Before June Revisions Rule SO2 310,230 - - 2012 After June Revisions Rule SO2 315,393 - - 2014 Before June Revisions Rule SO2 137,077 118% 161,751 2014 After June Revisions Rule SO2 142,240 118% 167,843 2012 Before June Revisions Rule Annual NOX 92,703 - - 2012 After June Revisions Rule Annual NOX 95,468 - - 2014 Before June Revisions Rule Annual NOX 87,493 118% 103,242 2014 After June Revisions Rule Annual NOX 90,258 118% 106,504 2012 Before June Revisions Rule Ozone-Season NOX 40,063 - - 2012 After June Revisions Rule Ozone-Season NOX 41,284 - - 2014 Before June Revisions Rule Ozone-Season NOX 37,792 121% 45,728 2014 After June Revisions Rule Ozone-Season NOX 39,013 121% 47,206 *Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations 
19) New York

EPA is finalizing, based on comments, an increase to New York’s SO2, annual NOX, and ozone season NOX budget i

assumption of near-term operational constraints affecting units at the East River plant, based on information provided by the 

that the plant is required to run for non-economic reasons. EPA's analysis in the final Transport Rule did not incorporate the conditions described in recently submitted documentation that appear likely to necessitate non-economic generation at the un

implementation of the Transport Rule programs. EPA is assuming additional generation will be dispatched from units at the 

immediate-term operational constraints provided by Con-Ed.73 As discussed later in this section, EPA assumes that the addit

from East River would offset generation that would otherwise come from combined cycle units within the state, and the revisis based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes o

and ozone season NOX budget are 84 ton, 694 ton, and 127 ton increases, respectively. 

The calculations of the increase in SO2, annual NOX, and ozone season NOX emissions due to out-of-merit-order disp

shown in Tables C.19.a., C.19.b., and C.19.c. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions fro

heat rate, generation from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A torder capacity factor is shown in column H. The additional generation for out-of-merit-order dispatch was calculated by mult

average out-of-merit-order capacity factor, and the number of hours in the ozone season (column I). The additional heat inpu

multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with th

were calculated by multiplying the additional heat input by the unit’s NOX emission rate. 

The East River units are part of the Manhattan District Heating System such that their emissions are driven by compl

electricity and steam demand, and all of these emissions are relevant to the state’s Transport Rule budgets. The emissions ad

tables affect the two steam units (Units 60 and 70) that did not operate in the EPA projections, but are required to run to supp

and also provide electricity. The remaining two units (Units 1 and 2) did operate in the EPA projections at reasonable levels 

adjustments. In addition, since Unit 70 operates as a electricity-only unit during in ozone season so that there is no ozone-seaeconomic operation, Unit 70 is not included in the revisions for the ozone season. In calculating the net impact on the state b

electricity generation would affect EPA’s prior projected emissions, as such generation is assumed to offset generation at oth

maintain the balance between modeled electricity supply and demand. Therefore, the heat input for each output is displayed 

generation that needs to be offset, which in this particular case represents only a fraction of the revised incremental heat inpu

73 See EPA-HQ-OAR-2009-0491-4761 and the document “Clarification of comments originally filed on the TR Revisions Rule by Con-E

docket (Docket No. EPA-HQ-OAR-2009-0491-4870). 
Table C.19.a.: Calculation to Determine New York SO2 Budget Revisions - Assuming out-of-merit-order dispa

A B C D E F G H I J K L Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual 

SO2Emissions from TR_ Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/ kWh) 

Annual Generation from TR_ Remedy Final_2012 (GWh) 

Annual 

SO2

Rate (lbs/ MMBtu) 

Annual Average Out-OfMeritOrder Capacity Factor For Electricity 

Additional Annual Generation* 

Additional Annual Elec Heat Input (MMBtu) 

Additional Annual Steam Heat Input (MMBtu) 

PoIfO

Calculation C*H*8.760 E*I East River 

2493_ B_60 134 0 12,830 0 0.31 36.1% 423.8 5,436,793 499,577 

East River 

2493_ B_70 180 0 11,980 0 0.31 15.4% 242.8 2,909,070 1,372,350 

Total 666.6 8,345,862 1,871,927 *The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield u** Average percentage of oil btu input at East River units 60 and 70 from 2010 EIA 923 data. 
Table C.19.b.: Calculation to Determine New York Annual NOX Budget Revisions - Assuming out-of-merit-order dis

A B C D E F G H I J Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Annual NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Annual Generation from TR_Remedy Final_2012 (GWh) 

Annual NOX

Rate (lbs/MMBtu) 

Annual Average Out-OfMerit-Order Capacity Factor For Electricity 

Additional Annual Generation* 

AdditionaAnnual Elec Heat Input (MMBtu) 

Calculation C*H*8.760 E*I East River 

2493_ B_60 134 0 12,830 0 0.13 36.1% 423.8 5,436,79

East River 

2493_ B_70 180 0 11,980 0 0.15 15.4% 242.8 2,909,07

Total 666.6 8,345,86*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield u
Table C.19.c.: Calculation to Determine New York Ozone-Season NOX Budget Revisions - Assuming out-of-merit-order 

A B C D E F G H I J Plant Name 

Unique Id 

Capacity 

(MW) 

2012 Ozone Season NOX

Emissions from TR_Remedy Final_2012 (1000 tons) 

Heat Rate (BTU/kWh) 

Ozone Season Generation from TR_Remedy Final_2012 (GWh) 

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone Season Average Out-OfMerit-Order Capacity Factor for Electricity 

Additional Ozone Season Generation* 

AdditionaOzone Season Elec Heat Input (MMBtu) 

Calculation C*H*3.672 E*I East River 60 134 0 12,830 0 0.13 29.3% 144.2 1,849,70*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield u

As calculated in Table C.19.d., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch 

generation at New York combined cycle units, shown in these calculations as a representative unit with a heat rate (column B

equal to the generation-weighted average of New York combined cycle units.74 The ozone season NO

X emissions associated 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the repre74 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Ca

rate averages used in Revisions Rule Part II” found in the Transport Rule docket (Docket No. EPA-HQ-OAR-2009-0491-4946). 
Table C.19.d.: Calculation of Emissions from Displaced Generation at New York Combined Cycle U

A B C D 

Program Period 

Displaced Generation (GWh) 

Heat Rate (BTU/kWh) 

 Emission Rate (lbs/MMBTU) 

Displaced NOX Emissions 

(tons) 

Calculation A*B*C/2000 SO2 667 7,236 0 0 Annual NOX 667 7,236 0.011824358 29 Ozone Season NOX 144 7,244 0.012305053 6 

The total revision to New York’s state budget due to the out-of-merit-order dispatch is calculated in Table C.19.e. Th

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the o

(row A) to determine the net emission budget changes for New York (row C). 

Table C.19.e.: Calculation to Determine Net New York SO2, Annual NOX and Ozone Season NOX Budge

Revisions (tons) 

2012 2014 

SO2

Annual 

NOX

Ozone 

Season 

NOX SO2

Annual 

NOX

Ozone 

Season NO

A 

Additional Emissions Due to Out-Of-Merit-Order Generation 84 722 133 84 722 133 

B 

Displaced Emissions from Out-Of-Merit-Order Generation 0 29 6 0 29 6 

C 

Net Budget Revisions for New York (A-B) 84 694 127 84 694 127 
 The total sum of changes to New York emission budgets in these revisions are shown in Table C.19.f. below. 

Table C.19.f.: Total Budget Revisions for New York (tons) 

Budget Year

Revisions due to 

Out-of-MeritOrder Dispatch Revisions Due to Unit Controls Total Change 

SO2 2012 84 5,360 5,444 SO2 2014 84 5,360 5,444 Annual NOX 2012 694 -- 694 Annual NOX 2014 694 -- 694 Ozone Season NOX 2012 127 -- 127 Ozone Season NOX 2014 127 -- 127 
The original and revised values for the state ozone season NO

X budget, assurance level, and new unit set-aside are de

Table C.19.g.: Impact of New York Budget Revisions for Controls and Out-Of-Merit-Order D

Revisions 

 Program Budget

Assurance 

Level 

T

% of 

Budget Tons 

% 

Bu

2012 Before June Revisions Rule SO2 30,852 - - 22012 After June Revisions Rule SO2 36,296 - - 22014 Before June Revisions Rule SO2 22,112 118% 26,092 22014 After June Revisions Rule SO2 27,556 118% 32,516 22012 Before June Revisions Rule Annual NO

X 21,028 - - 2

2012 After June Revisions Rule Annual NO

X 21,722 - - 2

2014 Before June Revisions Rule Annual NO

X 21,028 118% 24,813 2

2014 After June Revisions Rule Annual NO

X 21,722 118% 25,632 2

2012 Before June Revisions Rule Ozone-Season NO

X 10,242 - - 2

2012 After June Revisions Rule Ozone-Season NO

X 10,369 - - 2

2014 Before June Revisions Rule Ozone-Season NO

X 10,242 121% 12,393 2

2014 After June Revisions Rule Ozone-Season NO

X 10,369 121% 12,546 2

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations